WO2003036039A1

WO2003036039A1 - In situ production of a blending agent from a hydrocarbon containing formation

Info

Publication number: WO2003036039A1
Application number: PCT/US2002/034536
Authority: WO
Inventors: Harold J. Vinegar; Scott Lee Wellington; John Michael Karanikas; Meliha Deniz Sumnu-Dindoruk
Original assignee: Shell Internationale Research Maatschappij B.V.; Shell Canada Limited
Priority date: 2001-10-24
Filing date: 2002-10-24
Publication date: 2003-05-01
Also published as: WO2003036035A2; US7063145B2; US7077198B2; US20070209799A1; AU2002353888B1; IL161173A0; WO2003036031A2; US20030196801A1; WO2003036037A3; CN1575377B; CN100540843C; CA2462957A1; US20040211569A1; CA2463104A1; NZ532089A; IL161173A; WO2003035801A3; WO2003036032A2; US7066257B2; US20030196810A1

Abstract

An in situ process for treating a hydrocarbon containing formation is provided. The process may include providing heat from one or more heaters to at least a portion of the formation. The heat may be allowed to transfer from the reaction zone to a part of the formation such that heat from one or more heaters pyrolyzes at least some hydrocarbons within the part of the formation. A blending agent may be produced from the part of the formation, wherein a mixture produced with the blending agent has at least one selected property.

Description

IN SITU PRODUCTION OF A BLENDING AGENT FROM A HYDROCARBON CONTAINING

FORMATION

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations. Certain embodiments relate to producing a first hydrocarbon mixture from a formation, and blending the first hydrocarbon mixture with a second hydrocarbon mixture to produce a mixture that has one or more desired characteristics.

2. Description of Related Art

Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources 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 removed from the subterranean formation. The chemical and physical changes may result from in situ reactions that produce removable fluids, composition changes, solubility 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 fluid, an emulsion, a slurry, and/or a stream of solid particles with flow characteristics similar to fluid flow.

Large deposits of heavy hydrocarbons (e.g., heavy oil and/or tar) contained within formations (e.g., in tar sands) are found in North America, South America, and Asia. Tar sand deposits may be mined. Surface processes may separate bitumen from sand and/or other material removed along with the hydrocarbons. The separated bitumen may be converted to light hydrocarbons using conventional refinery methods. Mining and upgrading tar sand is usually substantially more expensive than producing lighter hydrocarbons from conventional oil reservoirs.

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. Heavy hydrocarbons produced from a hydrocarbon containing formation may be difficult to transport to a surface facility or refinery.

The cost of purchasing and/or transporting the light hydrocarbons to a formation site can add significant cost to a process for producing hydrocarbons from a formation. Thus, there is a need for methods and systems to economically produce and transport heavy hydrocarbons from a production site.

SUMMARY OF THE INVENTION

In an embodiment, heat is provided from a first set of heaters to a first section of a hydrocarbon containing formation to pyrolyze a portion of the hydrocarbons in the first section. Heat may also be provided from a second set of heaters to a second section of the formation. The heat may reduce the viscosity of hydrocarbons in the second section so that a portion of the hydrocarbons in the second section are able to move. A portion of the hydrocarbons from the second section may be induced to flow into the first section. A mixture of hydrocarbons may be produced from the formation. The produced mixture may include at least some pyrolyzed hydrocarbons. In an embodiment, heat is provided from heaters to a portion of a hydrocarbon containing formation. The heat may transfer from the heaters to a part of the formation of the formation to decrease a viscosity of hydrocarbons within the part of the formation. A gas may be provided to the part of the formation. The gas may displace hydrocarbons from the part of the formation towards one or more production wells. A mixture of hydrocarbons may be produced from the part of the formation through one or more production wells.

In certain embodiments, a quality of a produced mixture may be controlled by varying a location for producing the mixture. The location of production may be varied by varying the depth in the formation from which fluid is produced relative an overburden or underburden. The location of production may also be varied by varying which production wells are used to produce fluid. In some embodiments, the production wells used to remove fluid may be chosen based on a distance of the production wells from activated heaters.

In an embodiment, a blending agent may be produced from a part of a hydrocarbon containing formation. A portion of the blending agent may be mixed with heavy hydrocarbons to produce a mixture having one or more selected characteristics (e.g., density, viscosity, and/or stability).

In some embodiments, heat may be provided to a part of the formation to pyrolyze some hydrocarbons in a lower portion of the formation. A mixture of hydrocarbons may be produced from an upper portion of the formation. The mixture of hydrocarbons may include at least some pyrolyzed hydrocarbons from the lower portion of the formation.

In certain embodiments, a production rate of fluid from the formation may be controlled to adjust an average time that hydrocarbons in, or flowing into, a pyrolysis zone or exposed to pyrolysis temperatures. Controlling the production rate may allow for production of a large quantity of hydrocarbons of a desired quality from the formation.

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 a cross-sectional view of an embodiment for treating hydrocarbon containing formation containing heavy hydrocarbons with multiple heating sections.

FIG. 2 depicts a large pattern of heater and producer wells used in a simulation of an in situ process for a hydrocarbon containing formation.

FIG. 3 depicts a plan view of an embodiment of a hydrocarbon containing formation used to produce a first mixture that is blended with a second mixture.

FIG. 4 depicts SARA results (saturate/aromatic ratio versus asphaltene/resin ratio) for five blends. FIG. 5 depicts viscosity versus temperature for three blended mixtures. FIG. 6 illustrates oil production rates versus time for heavy hydrocarbons and light hydrocarbons in a simulation.

FIG. 7 illustrates oil production rates versus time for heavy hydrocarbons and light hydrocarbons with production inhibited for the first 500 days of heating in a simulation.

FIG. 8 illustrates percentage cumulative oil recovery versus time for three different horizontal producer well locations in a simulation. FIG. 9 illustrates production rates versus time for heavy hydrocarbons and light hydrocarbons for middle and bottom producer locations in a simulation.

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 that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

The following description generally relates to systems and methods for treating a hydrocarbon containing formation. Such formations may be treated to yield relatively high quality hydrocarbon products, hydrogen, and other products.

As used herein, "a method of treating a tar sands formation" may be used interchangeably with "an in situ conversion process for hydrocarbons." "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, bitumen, pyrobitumen, and oils. 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).

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.

"Carbon number" refers to a number of carbon atoms within a hydrocarbon molecule. A hydrocarbon fluid may include various hydrocarbons having varying numbers of carbon atoms. The hydrocarbon fluid may be described by a carbon number distribution. Carbon numbers and/or carbon number distributions may be determined by true boiling point distribution and/or gas-liquid chromatography.

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

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

"Condensable hydrocarbons" are hydrocarbons that condense at 25 °C at one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4. "Non-condensable hydrocarbons" are hydrocarbons that do not condense at 25 °C and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.

"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, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20°. Heavy oil, for example, generally has an API gravity of about 10- 20°, whereas tar generally has an API gravity below about 10°. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15 °C. Heavy hydrocarbons may also include aromatics or other complex ring hydrocarbons. "Tar" is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15 °C.

The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10°.

A "tar sands formation" is a formation that includes heavy hydrocarbons and/or tar entrained in sand, sandstones, carbonates, fractured carbonates, volcanics, basement, or other host lithologies. In some cases, a portion or all of a hydrocarbon portion of a tar sands formation may be predominantly hydrocarbons with no supporting framework and only floating (or no) mineral matter.

An in situ process may be used to provide heat to mobilize and/or pyrolyze hydrocarbons within a hydrocarbon containing formation to produce hydrocarbons from the formation that are not producible using current production techniques such as surface mining, solution extraction, etc. Such hydrocarbons may exist in relatively deep hydrocarbon containing formations. For example, such hydrocarbons may exist in a hydrocarbon containing formation that is greater than about 500 m below a ground surface but less than about 700 m below the surface.

Hydrocarbons within these relatively deep hydrocarbon containing formations may be at a relatively cool temperature such that the hydrocarbons are substantially immobile. Hydrocarbons found in deeper formations (e.g., a depth greater than about 700 m below the surface) may be somewhat more mobile due to increased natural heating of the formations as formation depth increases below the surface. Hydrocarbons may be more readily produced from these deeper formations because of their mobility. However, these hydrocarbons will generally be heavy hydrocarbons with an API gravity below about 20°. In some embodiments, the API gravity may be below about 15° or below about 10°.

FIG. 1 depicts a cross-sectional representation of an embodiment for treating heavy hydrocarbons in a formation with multiple heating sections. Heat sources 10 may be placed within hydrocarbon containing layer 12. Heat sources 10 may be placed at different angles in hydrocarbon layer 12. In some embodiments, heat sources 10 may be placed substantially vertical with hydrocarbon layer 12. In other embodiments, heater source 10 may be placed substantially horizontally within hydrocarbon layer 12. Heat sources 10 may be placed in a desired pattern (e.g., hexagonal, triangular, square, etc.). In an embodiment, heat sources 10 are placed in triangular patterns as shown in FIG. 1. A spacing between heat sources 10 may be less than about 25 m within first section 14 or, in some embodiments, less about 20 m or less than about 15 m. A volume of first section 14 (as well as second sections 16 and third sections 18) may be determined by a pattern and spacing of heat sources 10 within the section and/or a heat output of the heat sources. Sections 14, 16 and 18 of hydrocarbon layer may be between overburden 18 and/or underburden 20. Over/burden and /or underburden may form a perimeter barrier. 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.

Production wells 22 may be placed within first section 14. A number, orientation, and/or location of production wells 22 may be determined by considerations including, but not limited to, a desired production rate, a selected product quality, and/or a ratio of heavy hydrocarbons to light hydrocarbons. For example, one production well 22 may be placed in an upper portion of first section 14 as shown in FIG. 1.

In some embodiments, an injection well 24 is placed in first section 14. Injection well 24 (and/or a heat source or production well) may be used to provide a pressurizing fluid into first section 14. The pressurizing fluid may include, but is not limited to, carbon dioxide, N₂, CH₄, steam, combustion products, non-condensable fluid produced from the formation or combinations thereof. In certain embodiments, a location of injection well 24 is chosen such that the recovery of fluids from first section 14 is increased with the provided pressurizing fluid.

In an embodiment, heat sources 10 are used to provide heat to first section 14. First section 14 may be heated such that at least some heavy hydrocarbons within the first section are mobilized. A temperature at which at least some hydrocarbons are mobilized (i.e., a mobilization temperature) may be between about 50 °C and about 210 °C. In other embodiments, a mobilization temperature is between about 50 °C and about 150 °C or between about 50 °C and about 100 °C.

In an embodiment, a first mixture is produced from first section 14. The first mixture may be produced through production well 22 or production wells and/or heat sources 10. The first mixture may include mobilized fluids from the first section. The mobilized fluids may include at least some hydrocarbons from first section 14. In certain embodiments, the mobilized fluids produced include heavy hydrocarbons. An API gravity of the first mixture may be less than about 20°, less than about 15°, or less than about 10°. In some embodiments, the first mixture includes at least some pyrolyzed hydrocarbons. Some hydrocarbons may be pyrolyzed in portions of first section 14 that are at higher temperatures than a remainder of the first section. For example, portions adjacent heat sources 10 may be at somewhat higher temperatures (e.g., approximately 50 °C to approximately 100 °C higher) than the remainder of first section 14. As shown in FIG. 1, second sections 16 may be adjacent to first section 14. Second section 16 may include heat sources 10. Heat sources 10 in second section 16 may be arranged in a pattern similar to a pattern of heat sources 10 in first section 14. In some embodiments, heat sources 10 in second section 16 are arranged in a different pattern than heat sources 10 in first section 14 to provide desired heating of the second section. In certain embodiments, a spacing between heat sources 10 in second section 16 is greater than a spacing between heat sources 10 in first section 14. Heat sources 10 may provide heat to second section 16 to mobilize at least some hydrocarbons within the second section. In an embodiment, temperature within first section 14 may be increased to a pyrolyzation temperature after production of the first mixture. A pyrolyzation temperature in the first section may be between about 225 °C and about 375 °C. In some instances, a pyrolyzation temperature in the first section may be at least about 250 °C, or at least about 275 °C. Mobilized fluids (e.g., mobilized heavy hydrocarbons) from second section 16 may be allowed to flow into first section 14. Some of the mobilized fluids from second section 16 that flow into first section 14 may be pyrolyzed within the first section. Pyrolyzing the mobilized fluids in first section 14 may upgrade a quality of fluids (e.g., increase an API gravity of the fluid).

In certain embodiments, a second mixture is produced from first section 14. The second mixture may be produced through production well 22 or production wells and/or heat sources 10. The second mixture may include at least some hydrocarbons pyrolyzed within first section 14. Mobilized fluids from second section 16 and/or hydrocarbons originally within first section 14 may be pyrolyzed within the first section. Conversion of heavy hydrocarbons to light hydrocarbons by pyrolysis may be controlled by controlling heat provided to first section 14 and second section 16. In some embodiments, the heat provided to first section 14 and second section 16 is controlled by adjusting the heat output of a heat source or heat sources 10 within the first section. In other embodiments, the heat provided to first section 14 and second section 16 is controlled by adjusting the heat output of a heat source or heat sources 10 within the second section. The heat output of heat sources 10 within first section 14 and second section 16 may be adjusted to control the heat distribution within hydrocarbon containing layer 12 to account for the flow of fluids along a vertical and/or horizontal plane within the formation. For example, the heat output may be adjusted to balance heat and mass fluxes within the formation so that mass within the formation (e.g., fluids and mineral matrix within the formation) is substantially uniformly heated.

Producing fluid from production wells in the first section may create a pressure gradient with low pressures located at the production wells. The pressure gradient may draw mobilized fluid from adjacent sections into the first section. In some embodiments, a pressurizing fluid is provided in second section 16 (e.g., through injection well 24) to increase displacement of hydrocarbons within the second section towards the first section. The pressurizing fluid may enhance the pressure gradient in the formation to flow mobilized hydrocarbons into first section 14. In certain embodiments, the production of fluids from first section 14 allows the pressure in second section 16 to remain below a lithostatic pressure (e.g., below a pressure that allows fracturing of the overburden).

As shown in FIG. 1, third section 18 may be adjacent to second section 16. Heat may be provided to third section 18 from heat sources 10. Heat sources 10 in third section 18 may be arranged in a pattern similar to a pattern of heat sources 10 in first section 14 and/or heat sources in the second section 16. In some embodiments, heat sources 10 in third section 18 are arranged in a different pattern than heat sources 10 in first section 14 and/or heat sources in the second section 16. In certain embodiments, a spacing between heat sources 10 in third section 18 is greater than a spacing between heat sources 10 in first section 14. Heat sources 10 may provide heat to third section 18 to mobilize at least some hydrocarbons within the third section. In an embodiment, a temperature within second section 16 may be increased to a pyrolyzation temperature after production of the first mixture. Mobilized fluids from third section 18 may be allowed to flow into second section 16. Some of the mobilized fluids from third section 18 that flow into second section 16 may be pyrolyzed within the second section. A mixture may be produced from second section 16. The mixture produced from second section 16 may include at least some pyrolyzed hydrocarbons. An API gravity of the mixture produced from second section 16 may be at least about 20°, 30°, or 40°. The mixture may be produced through production wells

22 and/or heat sources 10 placed in second section 16. Heat provided to third section 18 and second section 16 may be controlled to control conversion of heavy hydrocarbons to light hydrocarbons and/or a desired characteristic of the mixture produced in the second section.

In another embodiment, mobilized fluids from third section 18 are allowed to flow through second section 16 and into first section 14. At least some of the mobilized fluids from third section 18 may be pyrolyzed in first section 14. In addition, some of the mobilized fluids from third section 18 may be produced as a portion of the second mixture in first section 14. The heavy hydrocarbon fraction in produced fluids may decrease as successive sections of the formation are produced through first section 14.

In some embodiments, a pressurizing fluid is provided in third section 18 (e.g., through injection well 24) to increase displacement of hydrocarbons within the third section. The pressurizing fluid may increase a flow of mobilized hydrocarbons into second section 16 and/or first section 14. For example, a pressure gradient may be produced between third section 18 and first section 14 such that the flow of fluids from the third section towards the first section is increased.

In an embodiment, heat provided to first section 14, second section 16 and/or other sections is turned on at the same time or within a short time of each other. In an embodiment, heat provided to second section 16, third section 18, and any subsequent sections may be turned on simultaneously after first section 14 has been substantially depleted of hydrocarbons and other fluids (e.g., brine). In other embodiments, sections may be turned on in a staggered pattern. The delay between turning on first section 14 and subsequent sections (e.g., second section 16, third section 18, etc.) may be, for example, about 1 year, about 1.5 years, or about 2 years.

Hydrocarbons may be produced from first section 14 and/or second section 16 such that at least about 50 % by weight of the initial mass of hydrocarbons in the formation is produced. In other embodiments, at least about

60 % by weight or at least about 70 % by weight of the initial mass of hydrocarbons in the formation is produced.

A large pattern simulation of an in situ process in a hydrocarbon containing formation was performed using a 3-D simulation. FIG. 2 depicts a pattern of heat sources 10 and production wells 22(A-E) placed in hydrocarbon containing layer 12 and used in the large pattern simulation. Heat sources 10 and production wells 22(A-E) were placed horizontally within hydrocarbon containing layer 12 with a length of 1000 m. Hydrocarbon containing layer 12 had a horizontal width of 145 m and a vertical height of 28 m. Five production wells 22(A-E) were placed within the pattern of heat sources 10 and with the spacings as shown in FIG. 2.

A first stage of heating included turning on heat sources 10 in first section 26. Production during the first stage of heating was through production well 22 A in first section 26. A minimum pressure for production in production well 22A was set at 6.8 bars absolute. Fluids were produced through production well 22A as the fluids were mobilized and/or pyrolyzed within hydrocarbon containing layer 12. The first stage of heating occurred for the first 360 days of the simulation.

A second stage of heating included turning on heat sources 10 in second section 28, third section 30, fourth section 32 and fifth section 34. Heat sources 10 in second section 28, third section 30, fourth section 32 and fifth section 34 were turned on at 360 days. Minimum pressure for production in production wells 22(B-E) was set at

6.8 bars absolute.

Heat sources 10 in first section 26 were turned off at 1860 days. At 1860 days, production through production well 22 A was also shut off. Heat sources 10 in other sections 28, 30, 32, 34 were similarly turned off after 2200 days. The simulation ended at 2580 days with production through production wells 22(B-E) remaining on. Heat sources 10 were maintained at a relatively constant heat output of 1 150 watts per meter. Production after the first stage of heating was through any one of production wells 22(A-E). Because fluids were produced through production well 22A at earlier times, fluids in the formation tended to flow towards production well 22 A as the fluids were mobilized and/or pyrolyzed in other sections of hydrocarbon containing layer 12. Fluids flow was largely due to vapor phase transport of fluids within hydrocarbon containing layer 12. A maximum average pressure in fifth section 34 remained below about 100 bars absolute around 800 days into the simulation. Pressure then decreased as fluids were mobilized within fifth section 34 (i.e., the average temperature increased above about 100 °C).

Oil production slowly increased for approximately the first 1500 days and then increased rapidly after about 1500 days to a maximum of about 880 nrVday at about 1785 days. After about 1785 days, production rate decreased as a majority of fluids are produced from hydrocarbon containing layer 12. The high production rate at about 1785 days may be due to a high rate of vapor phase transport in the formation following pyrolysis of hydrocarbons in the formation.

Gas production slowly increased for approximately the first 1500 days and then increased rapidly after about 1500 days to a maximum of about 23500 m³/day at about 1800 days. The maximum gas production rate occurred at a substantially similar time to the maximum oil production rate. Thus, the maximum oil production rate may be primarily due to a high gas production rate.

A quality of produced hydrocarbon fluids from a hydrocarbon containing formation may be described by a carbon number distribution. In general, lower carbon number products such as products having carbon numbers less than about 25 may be considered to be more valuable than products having carbon numbers greater than about 25. In an embodiment, treating a hydrocarbon containing formation may include providing heat to at least a portion of a formation to produce hydrocarbon fluids from the formation of which a majority of the produced fluid may have carbon numbers of less than approximately 25, or, for example, less than approximately 20. For example, less than about 20 weight % of the produced condensable fluid may have carbon numbers greater than about 20. Heavy hydrocarbons produced from a hydrocarbon containing formation may be mixed with light hydrocarbons so that the heavy hydrocarbons can be transported to a surface facility or refinery (e.g., pumping the hydrocarbons through a pipeline). In some embodiments, the light hydrocarbons (such as naphtha) are brought in through a second pipeline (or are trucked) from other areas (such as a surface facility or another production site) to be mixed with the heavy hydrocarbons. The cost of purchasing and/or transporting the light hydrocarbons to a formation site can add significant cost to a process for producing hydrocarbons from a formation. In an embodiment, producing the light hydrocarbons at or near a formation site (e.g., less than about 100 km from the formation site) that produces heavy hydrocarbons instead of using a second pipeline for supply of the light hydrocarbons may allow for use of the second pipeline for other purposes. The second pipeline may be used, in addition to a first pipeline already used for pumping produced fluids, to pump produced fluids from the formation site to a surface facility. Use of the second pipeline for this purpose may further increase the economic viability of producing light hydrocarbons (i.e., blending agents) at or near the formation site. Another option is to build a surface facility or refinery at a formation site. However, this can be expensive and, in some cases, not possible.

In an embodiment, light hydrocarbons (e.g., a blending agent) may be produced at or near a formation site that produces heavy hydrocarbons (i.e., near the production site of heavy hydrocarbons). The light hydrocarbons may be mixed with heavy hydrocarbons to produce a transportable mixture. The transportable mixture may be introduced into a first pipeline used to transport fluid to a remote refinery or transportation facility, which may be located more than about 100 km from the production site. The transportable mixture may also be introduced into a second pipeline that was previously used to transport a blending agent (e.g., naphtha) to or near the production site. Producing the blending agent at or near the production site may allow the ability to significantly increase throughput to the remote refinery or transportation facility without installation of additional pipelines. Additionally, the blending agent used may be recovered and sold from the refinery instead of being transported back to the heavy hydrocarbon production site. The transportable mixture may also be used as a raw material feed for a production process at the remote refinery.

Throughput of heavy hydrocarbons to an existing remote surface facility may be a limiting factor in embodiments that use a two pipeline system with one of the pipelines dedicated to transporting a blending agent to the heavy hydrocarbon production site. Using a blending agent produced at or near the heavy hydrocarbon production site may allow for a significant increase in the throughput of heavy hydrocarbons to the remote surface facility. In some embodiments, the blending agent may be used to clean tanks, pipes, wellbores, etc. The blending agent may be used for such purposes without precipitating out components cleaned from the tanks, pipes, or wellbores.

In an embodiment, heavy hydrocarbons are produced as a first mixture from a first section of a hydrocarbon containing formation. Heavy hydrocarbons may include hydrocarbons with an API gravity below about 20°, 15°, or 10°. Heat provided to the first section may mobilize at least some hydrocarbons within the first section. The first mixture may include at least some mobilized hydrocarbons from the first section. Heavy hydrocarbons in the first mixture may include a relatively high asphaltene content compared to saturated hydrocarbon content. For example, heavy hydrocarbons in the first mixture may include an asphaltene content to saturated hydrocarbon content ratio greater than about 1, greater than about 1.5, or greater than about 2.

Heat provided to a second section of the formation may pyrolyze at least some hydrocarbons within the second section. A second mixture may be produced from the second section. The second mixture may include at least some pyrolyzed hydrocarbons from the second section. Pyrolyzed hydrocarbons from the second section may include light hydrocarbons produced in the second section. The second mixture may include relatively higher amounts (as compared to heavy hydrocarbons or hydrocarbons found in the formation) of hydrocarbons such as naphtha, methane, ethane, or propane (i.e., saturated hydrocarbons) and/or aromatic hydrocarbons. In some embodiments, light hydrocarbons may include an asphaltene content to saturated hydrocarbon content ratio less than about 0.5, less than about 0.05, or less than about 0.005.

A condensable fraction of the light hydrocarbons of the second mixture may be used as a blending agent. The presence of compounds in the blending agent in addition to naphtha may allow the blending agent to dissolve a large amount of asphaltenes and/or solid hydrocarbons. The blending agent may be used to clean tanks, pipelines or other vessels that have solid (or semi-solid) hydrocarbon deposits.

The light hydrocarbons of the second mixture may include less nitrogen, oxygen, and/or sulfur than heavy hydrocarbons. For example, light hydrocarbons may have a nitrogen, oxygen, and sulfur combined weight percentage of less than about 5 %, less than about 2 %, or less than about 1 %. Heavy hydrocarbons may have a nitrogen, oxygen, and sulfur combined weight percentage greater than about 10 %, greater than about 15 %, or greater than about 18 %. Light hydrocarbons may have an API gravity greater than about 20°, greater than about 30° or greater than about 40°.

The first mixture and the second mixture may be blended to produce a third mixture. The third mixture may be formed in a surface facility located at or near production facilities for the heavy hydrocarbons. The third mixture may have a selected API gravity. The selected API gravity may be at least about 10° or, in some embodiments, at least about 20° or 30°. The API gravity may be selected to allow the third mixture to be efficiently transported (e.g., through a pipeline).

A ratio of the first mixture to the second mixture in the third mixture may be determined by the API gravities of the first mixture and the second mixture. For example, the lower the API gravity of the first mixture, the more of the second mixture that may be needed to produce a selected API gravity in the third mixture.

Likewise, if the API gravity of the second mixture is increased, the ratio of the first mixture to the second mixture may be increased. In some embodiments, a ratio of the first mixture to the second mixture in the third mixture is at least about 3: 1. Other ratios may be used to produce a third mixture with a desired API gravity. In certain embodiments, a ratio of the first mixture to the second mixture is chosen such that a total mass recovery from the formation will be as high as possible. In one embodiment, the ratio of the first mixture to the second mixture may be chosen such that at least about 50 % by weight of the initial mass of hydrocarbons in the formation is produced. In other embodiments, at least about 60 % by weight or at least about 70 % by weight of the initial mass of hydrocarbons may be produced. In some embodiments, the first mixture and the second mixture are blended in a specific ratio that may increase the total mass recovery from the formation compared to production of only the second mixture from the formation (i.e., in situ processing of the formation to produce light hydrocarbons).

The ratio of the first mixture to the second mixture in the third mixture may be selected based on a desired viscosity, desired boiling point, desired composition, desired ratio of components (e.g., a desired asphaltene to saturated hydrocarbon ratio or a desired aromatic hydrocarbon to saturated hydrocarbon ratio), and/or desired density of the third mixture. The viscosity and/or density may be selected such that the third mixture is ^■ transportable through a pipeline or usable in a surface facility. In some embodiments, the viscosity (at about 4 °C) may be selected to be less than about 7500 centistokes (cs) less than about 2000 cs, less than about 100 cs, or less than about 10 cs. Centistokes is a unit of kinematic viscosity. Kinematic viscosity multiplied by the density yields absolute viscosity. The density (at about 4 °C) may be selected to be less than about 1.0 g/cm³, less than about 0.95 g/cm³, or less than about 0.9 g/cm³. The asphaltene to saturated hydrocarbon ratio may be selected to be less than about 1, less than about 0.9, or less than about 0.7. The aromatic hydrocarbon to saturated hydrocarbon ratio may be selected to be less than about 4, less than about 3.5, or less than about 2.5.

In an embodiment, the ratio of the first mixture to the second mixture in the third mixture is selected based on the relative stability of the third mixture. A component or components of the third mixture may precipitate out of the third mixture. For example, asphaltene precipitation may be a problem for some mixtures of heavy hydrocarbons and light hydrocarbons. Asphaltenes may precipitate when fluid is de-pressurized (e.g., removed from a pressurized formation or vessel) and/or there is a change in mixture composition. For the third mixture to be transportable through a pipeline or usable in a surface facility, the third mixture may need a minimum relative stability. The minimum relative stability may include a ratio of the first mixture to the second mixture such that asphaltenes do not precipitate out of the third mixture at ambient and/or elevated temperatures. Tests may be used to determine desired ratios of the first mixture to the second mixture that will produce a relatively stable third mixture. For example, induced precipitation, chromatography, titration, and/or laser techniques may be used to determine the stability of asphaltenes in the third mixture. In some embodiments, asphaltenes precipitate out of a mixture but are held suspended in the mixture and, hence, the mixture may be transportable. A blending agent produced by an in situ process may have excellent blending characteristics with heavy hydrocarbons (i.e., low probability for precipitation of heavy hydrocarbons from a mixture with the blending agent). In certain embodiments, resin content in the second mixture (i.e., light hydrocarbon mixture) may determine the stability of the third mixture. For example, resins such as maltenes or resins containing heteroatoms such as N, S or O may be present in the second mixture. These resins may enhance the stability of a third mixture produced by mixing a first mixture with the second mixture. In some cases, the resins may suspend asphaltenes in the mixture and inhibit asphaltene precipitation.

In certain embodiments, market conditions may determine characteristics of a third mixture. Examples of market conditions may include, but are not limited to, demand for a selected octane of gasoline, demand for heating oil in cold weather, demand for a selected cetane rating in a diesel oil, demand for a selected smoke point for jet fuel, demand for a mixture of gaseous products for chemical synthesis, demand for transportation fuels with a certain sulfur or oxygenate content, or demand for material in a selected chemical process.

In an embodiment, a blending agent may be produced from a section of a hydrocarbon containing formation. "Blending agent" is a material that is mixed with another material to produce a mixture having a desired property (e.g., viscosity, density, API gravity, etc.). The blending agent may include at least some pyrolyzed hydrocarbons. The blending agent may include properties of the second mixture of light hydrocarbons described above. For example, the blending agent may have an API gravity greater than about 20°, greater than about 30°, or greater than about 40°. The blending agent may be blended with heavy hydrocarbons to produce a mixture with a selected API gravity. For example, the blending agent may be blended with heavy hydrocarbons with an API gravity below about 15° to produce a mixture with an API gravity of at least about 20°. In certain embodiments, the blending agent may be blended with heavy hydrocarbons to produce a transportable mixture (e.g., movable through a pipeline). In some embodiments, the heavy hydrocarbons are produced from another section of the hydrocarbon containing formation. In other embodiments, the heavy hydrocarbons may be produced from another hydrocarbon containing formation or any other formation containing heavy hydrocarbons.

In some embodiments, the first section and the second section of the formation may be at different depths within the same formation. For example, the heavy hydrocarbons may be produced from a section having a depth between about 500 m and about 1500 m, a section having a depth between about 500 m and about 1200 m, or a section having a depth between about 500 m and about 800 m. At these depths, the heavy hydrocarbons may be somewhat mobile (and producible) due to a relatively higher natural temperature in the reservoir. The light hydrocarbons may be produced from a section having a depth between about 10 m and about 500 m, a section having a depth between about 10 m and about 400 m, or a section having a depth between about 10 m and about 250 m. At these shallower depths, heavy hydrocarbons may not be readily producible because of the lower natural temperatures at the shallower depths. In addition, the API gravity of heavy hydrocarbons may be lower at shallower depths due to increased water washing and/or bacterial degradation. In other embodiments, heavy hydrocarbons and light hydrocarbons are produced from first and second sections that are at a similar depth below the surface. In another embodiment, the light hydrocarbons and the heavy hydrocarbons are produced from different formations. The different formations, however, may be located near each other.

In an embodiment, heavy hydrocarbons are cold produced from a formation (e.g., a formation in the Faja (Venezuela)) at depths between about 760 m and about 1070 m. The produced hydrocarbons may have an API gravity of less than about 9°. Cold production of heavy hydrocarbons is generally defined as the production of warm (i.e., mobilized) heavy hydrocarbons) without providing heat (or providing relatively little heat) to the formation or the production well. In other embodiments, the heavy hydrocarbons may be produced by steam injection or a mixture of steam injection and cold production. The heavy hydrocarbons may be mixed with a blending agent to transport the produced heavy hydrocarbons through a pipeline. In one embodiment, the blending agent is naphtha. Naphtha may be produced in surface facilities that are located remotely from the formation. When production of hydrocarbons from the formation is inhibited, the pressure in the formation may increase with increasing temperature in the formation because of thermal expansion and/or phase change of heavy hydrocarbons and other fluids (e.g., water) in the formation. Pressure within the formation may be maintained below a selected pressure to inhibit unwanted production, fracturing of the overburden or underburden, and/or coking of hydrocarbons in the formation. In some embodiments, the selected pressure may approach the lithostatic pressure or natural hydrostatic pressure of the formation. In an embodiment, the selected pressure may be about 35 bars absolute. Controlling production rate from production wells in the formation may control the pressure in the formation. In some embodiments, pressure in the formation may be controlled by releasing vapor within the formation through one or more pressure release wells in the formation. Pressure relief wells may be heat sources or separate wells inserted into the formation. Formation fluid removed from the formation through the relief wells may be sent to a surface facility. Producing at least some hydrocarbons from the formation may inhibit the pressure in the formation from rising above the selected pressure. In certain embodiments, some formation fluids may be back produced through a heat source wellbore. For example, some formation fluids may be back produced through a heat source wellbore during early times of heating of a hydrocarbon containing formation. In an embodiment, some formation fluids may be produced through a portion of a heat source wellbore. Injection of heat may be adjusted along the length of the wellbore so that fluids produced through the wellbore are not overheated. Fluids may be produced through portions of the heat source wellbore that are at lower temperatures than other portions of the wellbore.

Producing at least some formation fluids through a heat source wellbore may reduce or eliminate the need for additional production wells in a formation. In addition, pressures within the formation may be reduced by producing fluids through a heat source wellbore (especially within the region surrounding the heat source wellbore). Reducing pressures in the formation may increase the production of liquids and decrease the production of vapors from the formation. In certain embodiments, producing fluids through heat source wellbores may lead to earlier production of fluids from the formation. Portions of the formation closest to heat source wellbores will increase to mobilization and/or pyrolysis temperatures earlier than portions of the formation near production wells. Thus, fluids may be produced at earlier times from portions near the heat source wellbores.

In other embodiments, the heavy hydrocarbons may be mixed with a blending agent produced from a shallower section of the formation using an in situ conversion process. The shallower section may be at a depth less than about 400 m (e.g., less than about 150 m). The shallower section of the formation may contain heavy hydrocarbons with an API gravity of less than about 7°. The blending agent may include light hydrocarbons produced by pyrolyzing at least some of the heavy hydrocarbons from the shallower section of the formation. The blending agent may have an API gravity above about 35° (e.g., above about 40°). In certain embodiments, a blending agent may be produced in a first portion of a hydrocarbon containing formation and injected (e.g., into a production well) into a second portion of the hydrocarbon containing formation (or, in some embodiments, a second portion in another hydrocarbon containing formation). Heavy hydrocarbons may be produced from the second portion (e.g., by cold production). Mixing between the blending agent may occur within the production well and/or within the second portion of the formation. The blending agent may be produced through a production well in the first portion and pumped to a production well in the second portion. In some embodiments, non-hydrocarbon fluids (e.g., water or carbon dioxide), vapor-phase hydrocarbons, and/or other undesired fluids may be separated from the blending agent prior to mixing with heavy hydrocarbons.

Injecting the blending agent into a portion of a hydrocarbon containing formation may provide mixing of the blending agent and heavy hydrocarbons in the portion. The blending agent may be used to assist in the production of heavy hydrocarbons from the formation. The blending agent may reduce a viscosity of heavy hydrocarbons in the formation. Reducing the viscosity of heavy hydrocarbons in the formation may reduce the possibility of clogging or other problems associated with cold producing heavy hydrocarbons. In some embodiments, the blending agent may be at an elevated temperature and be used to provide at least some heat to the formation to increase the mobilization (i.e., reduce the viscosity) of heavy hydrocarbons within the formation. The elevated temperature of the blending agent may be a temperature proximate the temperature at which the blending agent is produced minus some heat losses during production and transport of the blending agent. In certain embodiments, the blending agent may be pumped through an insulated pipeline to reduce heat losses during transport.

The blending agent may be mixed with the cold produced heavy hydrocarbons in a selected ratio to produce a third mixture with a selected API gravity. For example, the blending agent may be mixed with cold produced heavy hydrocarbons in a 1 to 2 ratio or a 1 to 4 ratio to produce a third mixture with an API gravity greater than about 20°. In certain embodiments, the third mixture may have an overall API gravity greater than about 25° or an API gravity sufficiently high such that the third mixture is transportable through a conduit or pipeline. In some embodiments, the third mixture of hydrocarbons may have an API gravity between about 20° and about 45°. In other embodiments, the blending agent may be mixed with cold produced heavy hydrocarbons to produce a third mixture with a selected viscosity, a selected stability, and/or a selected density.

The third mixture may be transported through a conduit, such as a pipeline, between the formation and a surface facility or refinery. The third mixture may be transported through a pipeline to another location for further transportation (e.g., the mixture can be transported to a facility at a river or a coast through the pipeline where the mixture can be further transported by tanker to a processing plant or refinery). Producing the blending agent at the formation site (i.e., producing the blending agent from the formation) may reduce a total cost for producing hydrocarbons from the formation. In addition, producing the third hydrocarbon mixture at a formation site may eliminate a need for a separate supply of light hydrocarbons and/or construction of a surface facility at the site. In an embodiment, a third mixture of hydrocarbons produced from a hydrocarbon containing formation may include about 20 weight % light hydrocarbons or greater (e.g., about 50 weight % or about 80 weight % light hydrocarbons) and about 80 weight % heavy hydrocarbons or less (e.g., about 50 weight % or about 20 weight % heavy hydrocarbons). The weight percentage of light hydrocarbons and heavy hydrocarbons may vary depending on, for example, a weight distribution (or API gravity) of light and heavy hydrocarbons, a relatively stability of the third mixture or a desired API gravity of the mixture. In certain embodiments, the weight percentage of light hydrocarbons may be selected to blend the least amount of light hydrocarbons with heavy hydrocarbons that produces a mixture with a desired density or viscosity.

FIG. 3 depicts a plan view of an embodiment of a hydrocarbon containing formation used to produce a first mixture that is blended with a second mixture. Hydrocarbon containing formation 12 may include first section 36 and second section 38. First section 36 may be at depths greater than, for example, about 800 m below a surface of the formation. Heavy hydrocarbons in first section 36 may be produced through production well 22 placed in the first section. Heavy hydrocarbons in first section 36 may be produced without heating because of the depth of the first section. First section 36 may be below a depth at which natural heating mobilizes heavy hydrocarbons within the first section. In some embodiments, at least some heat may be provided to first section 36 to mobilize fluids within the first section.

Second section 38 may be heated using heat sources 10 placed in the second section. Heat sources 10 are depicted as substantially horizontal heat sources in FIG. 3. Heat provided by heat sources 10 may pyrolyze at least some hydrocarbons within second section 38. Pyrolyzed fluids may be produced from second section 38 through production well 22'. Production well 22' is depicted as a substantially vertical production well in FIG. 3.

In an embodiment, heavy hydrocarbons from first section 36 are produced in a first mixture through production well 22. Light hydrocarbons (i.e., pyrolyzed hydrocarbons) may be produced in a second mixture through production well 22'. The first mixture and the second mixture may be mixed to produce a third mixture in surface facility 40. The first and the second mixture may be mixed in a selected ratio to produce a desired third mixture. The third mixture may be transported through pipeline 42 to a production facility or a transportation facility. The production facility or transportation facility may be located remotely from surface facility 40. In some embodiments, the third mixture may be trucked or shipped to a production facility or transportation facility. In certain embodiments, surface facility 40 may be a simple mixing station to combine the mixtures produced from production well 22 and production well 22'.

In certain embodiments, the blending agent produced from second section 38 may be injected through production well 22 into first section 36. A mixture of light hydrocarbons and heavy hydrocarbons may be produced through production well 22 after mixing of the blending agent and heavy hydrocarbons in first section 36. In some embodiments, the blending agent may be produced by separating non-desirable components (e.g., water) from a mixture produced from second section 38. The blending agent may be produced in surface facility. The blending agent may be pumped from surface facility through production well 22 and into first section 36.

FIGS. 4 and 5 depict results from an experiment. In the experiment, blending agent 50 produced by pyrolysis was mixed with Athabasca tar (heavy hydrocarbons 52) in three blending mixtures of different ratios. First mixture 54 included 80 % blending agent 50 and 20 % heavy hydrocarbons 52. Second mixture 56 included

50 % blending agent 50 and 50 % heavy hydrocarbons 52. Third mixture 58 included 20 % blending agent 50 and 80 % heavy hydrocarbons 52. Composition, physical properties, and asphaltene stability were measured for the blending agent, heavy hydrocarbons, and each of the mixtures.

Table 1 presents results of composition measurements of the mixtures. SARA analysis determined composition on a topped oil basis. SARA analysis includes a combination of induced precipitation (for asphaltenes) and column chromatography. Whole oil basis compositions were also determined.

Table 1

Key:

Sat Saturates

Aro Aromatics

NSO Resins (containing heteroatoms such as N, S and O)

Asph Asphaltenes

Asphaltene content on a whole oil basis varies linearly with the percentage of blending agent 50 in the mixture. FIG. 4 depicts SARA results (saturate/aromatic ratio versus asphaltene/resin ratio) for each of the blends (50, 52, 54, 56 and58). The line in FIG. 4 represents the differentiation between stable mixtures and unstable mixtures based on SARA results. The topping procedure used for SARA removed a greater proportion of the contribution of blending agent 50 (as compared to whole oil analysis) and resulted in the non-linear distribution in FIG. 4. First mixture 54, second mixture 56 and third mixture 58 plotted closer to heavy hydrocarbons 52 than blending agent 50. In addition, second mixture 56 and third mixture 58 plotted relatively closely. All blends (50, 52, 54, 56 and 58 ) plotted in a region of marginal stability.

Blending agent 50 included very little asphaltene (0.01 % by weight, whole oil basis). Heavy hydrocarbons 52 included about 13.2 % by weight (whole oil basis) with the amount of asphaltenes in the mixtures (54, 56, and 58) varying between 2.2 % by weight and 10.3 % by weight on a whole oil basis. Other indicators of the gross oil properties is the ratio between saturates and aromatics and the ratio between asphaltenes and resins. The asphaltene/resin ratio was lowest for first mixture 54, which has the largest percentage of blending agent 40. Second mixture 56 and third mixture 58 had relatively similar asphaltene/resin ratios indicating that the majority of resins in the mixtures are due to contribution from heavy hydrocarbons 52. The saturate/aromatic ratio was relatively similar for each of the mixtures.

Density and viscosity of the mixtures were measured at three temperatures 4.4 °C (40 °F), 21 °C (70 °F), and 32 °C (90 °F). The density and API gravity of the mixtures were also determined at 15 °C (60 °F) and used to calculate API gravities at other temperatures. In addition, a Floe Point Analyzer (FPA) value was determined for each of the three blended mixtures (54, 56 and 58). FPA is determined by n-heptane titration. The floe point is detected with a near infrared laser. The light source is blocked by asphaltenes precipitating out of solution. The FPA test was calibrated with a set of known problem and non-problem mixtures. Generally, FPA values less than 2.5 are considered unstable, greater than 3.0 are considered stable, and 2.5-3.0 are considered marginal. Table 2 presents values for FPA, density, viscosity, and API gravity for the three blended mixtures at four temperatures. Table 2

Key:

FPA Flocculation Point Analyzer value

Spec. Grav. Specific Gravity relative to water

Density (g/cc) Density in grams per cubic centimeter

API API gravity relative to water

Vise, (cs) Viscosity in centistokes

FPA tests showed that the mixtures containing lower amounts of heavy hydrocarbons were less stable. The lower stability was likely due to the proportion of aliphatic components already in these mixtures, which reduces asphaltene solubility. First mixture 54 was the least stable with a FPA value of 1.5, indicating instability with respect to asphaltene precipitation.

Second mixture 56 exhibited different behavior. Second mixture 56 had a FPA value of 2.2 indicating instability with respect to asphaltene precipitation. FPA analysis showed that the asphaltenes were precipitated, re- dissolved, and then re-precipitated with continuous addition of n-heptane.

FPA analysis of third mixture 58 showed that the asphaltenes were precipitated, re-dissolved, and then re- precipitated with continuous addition of n-heptane, as found for second mixture 56. The first precipitation in third mixture 58, however, was less pronounced than for second mixture 56. The FPA value of 2.8 found for third mixture 58 indicates marginal stability for the third mixture. Slow homogenization, associated with a high viscosity of the sample mixtures, is most likely responsible for the precipitation, re-dissolving, and re-precipitation with continued n-heptane addition.

Each of the mixtures (54, 56, and 58) showed relatively similar changes in density with increasing temperature. API values increased correspondingly with decreasing density. Viscosity changes, however, varied between each of the mixtures.

First mixture 54 was the least affected by temperature with viscosity values at 21 °C and 32 °C determined to be about 70 % and about 57 % of that at 4.4 °C, respectively. Second mixture 56 had viscosity values that decreased to values (of that at 4.4 °C) of about 48 % at 21 °C and about 30 % at 32 °C. Third mixture 58 was the most affected by temperature with viscosity values of about 21 % and about 9 % at 21 °C and 32 °C, respectively. Viscosity changes are approximately linear on a logarithmic plot of viscosity versus temperature as shown in FIG. 5.

Laboratory experiments were conducted on three tar samples contained in their natural sand matrix. The three tar samples were collected from the Athabasca tar sand region in western Canada. In each case, core material received from a well was mixed and then was split. One aliquot of the split core material was used in the retort, and the replicate aliquot was saved for comparative analyses. Materials sampled included a tar sample within a sandstone matrix. The heating rate for the runs was varied at 1 °C/day, 5 °C/day, and 10 °C/day. The pressure condition was varied for the runs at pressures of 1 bar, 7.9 bars, and 28.6 bars. Run #78 was operated with no backpressure (about 1 bar absolute) and a heating rate of 1 °C/day. Run #79 was operated with no backpressure (about 1 bar absolute) and a heating rate of 5 °C/day. Run #81 was operated with no backpressure (about 1 bar absolute) and a heating rate of 10 °C/day. Run #86 was operated at a pressure of 7.9 bars absolute and a heating rate of 10 °C/day. Run #96 was operated at a pressure of 28.6 bars absolute and a heating rate of 10 °C/day. In general, 0.5 to 1.5 kg initial weight of the sample was required to fill the available retort cells.

Table 3 illustrates the elemental analysis of initial tar and of the produced fluids for runs #81, #86, and #96. These data are all for a heating rate of 10 °C/day. Only pressure was varied between the runs.

TABLE 3

As illustrated in Table 3, pyrolysis of the tar sand decreases nitrogen, sulfur and oxygen weight percentages in a produced fluid. Increasing the pressure in the pyrolysis experiment appears to decrease the nitrogen, sulfur and oxygen weight percentage in the produced fluids. In addition, the weight percentage of hydrogen and the hydrogen to carbon ratio increase with increasing pressure.

Table 4 illustrates NOISE (Nitric Oxide Ionization Spectrometry Evaluation) analysis data for runs #81 , #86, and #96 and the initial tar. The remaining weight percentage (47.2%) in the initial tar may be found in the high molecular weight residue. TABLE 4

Product Fluid Analysis Run #

Initial tar 81 86 96

P(bar) 1 7.9 28.6

Paraffins (wt%) 7.08 15.36 27.16 26.45

Cycloalkanes (wt%) 29.15 46.7 45.8 36.56

Phenols (wt%) 0 0.34 0.54 0.47

Mono-aromatics (wt%) 6.73 21.04 16.88 28.0

Di-aromatics (wt%) 8.12 14.83 9.09 28.6

Tri-aromatics (wt%) 1.7 1.72 0.53 0

Tetra-aromatics (wt%) 0.02 0.01 0 0

As illustrated in Table 4, pyrolyzation of tar sand produces a product fluid with a significantly higher weight percentage of paraffins, cycloalkanes, and mono-aromatics than found in the initial tar sand. Increasing the pressure up to 7.9 bars absolute appears to substantially eliminate the production of tetra-aromatics. Further increasing the pressure up to 28.6 bars absolute appears to substantially eliminate the production of tri-aromatics. An increase in the pressure also appears to decrease production of di-aromatics. Increasing the pressure up to 28.6 bars absolute also appears to significantly increase production of mono-aromatics. This may be due to an increased hydrogen partial pressure at the higher pressure. The increased hydrogen partial pressure may reduce the number of poly-aromatic compounds and increase the number of mono-aromatics, paraffins, and/or cycloalkanes.

FIG. 6 illustrates oil production rates (m³/day) versus time (in days) for heavy hydrocarbons 52 and light hydrocarbons 60 as determined by computer simulation techniques. Heavy hydrocarbon production 52 reached a maximum of about 3 m³/day at about 150 days. Light hydrocarbon production 60 reached a maximum of about 9.6 m³/day at about 950 days. In addition, almost all heavy hydrocarbon production 52 was complete before the onset of light hydrocarbon production 60. The early heavy hydrocarbon production was attributed to production of cold (relatively unheated and unpyrolyzed) heavy hydrocarbons.

In some embodiments, early production of heavy hydrocarbons may be undesirable. FIG. 7 illustrates oil production rates (m³/day) versus time (days) for heavy hydrocarbons 52 and light hydrocarbons 60 with production inhibited for the first 500 days of heating as determined by simulation of treatment of the formation. Heavy hydrocarbon production 52 in FIG. 7 was significantly lower than heavy hydrocarbon production 52 in FIG. 6. Light hydrocarbon production 60 in FIG. 7 was higher than light hydrocarbon production 60 in FIG. 6, reaching a maximum of about 11.5 m³/day at about 950 days. The percentage of light hydrocarbons to heavy hydrocarbons was increased by inhibiting production the first 500 days of heating. FIG. 8 illustrates percentage cumulative oil recovery versus time (days) for three different horizontal producer well locations: top 62, middle 64, and bottom 66 as determined by simulation of treatment of the formation. The highest cumulative oil recovery was obtained using bottom producer 66. There was relatively little difference in cumulative oil recovery between middle producer 64 and top producer 66.

FIG. 9 illustrates production rates (m³/day) versus time (days) for heavy hydrocarbons and light hydrocarbons for a middle producer location and a bottom producer location as determined by simulation of treatment of the formation. As seen in FIG. 9, heavy hydrocarbon production 68 from the bottom producer was more than heavy hydrocarbon production 70 from the middle producer. There was relatively little difference between light hydrocarbon production 72 from the bottom producer and light hydrocarbon production 74 from the middle producer. Higher cumulative oil recovery obtained with the bottom producer (shown in FIG. 8) may be due to increased heavy hydrocarbon production.

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.

Claims

WHAT IS CLAIMED:

1. A method for treating a hydrocarbon containing formation in situ, comprising: providing heat from one or more heaters to a part of the formation such that the heat provided to the part of the formation pyrolyzes at least some hydrocarbons; and producing a blending agent from the part of the formation, wherein at least a portion of the blending agent is adapted to blend with a fluid to produce a mixture with a selected property.

2. The method of claim 1, wherein the fluid is a viscous fluid comprising at least some heavy hydrocarbons and the blending agent is adapted to blend with the viscous fluid to produce the mixture with a lower viscosity than the fluid.

3. The method of one or more of claims 1-2, wherein the fluid comprises a viscous crude oil having an API gravity below about 15°.

4. The method of one or more of claims 1-3, further comprising producing the fluid from a second part of a hydrocarbon containing formation and blending the fluid with the blending agent to produce the mixture.

5. The method of claim 1-3, further comprising producing the fluid from a second part of a hydrocarbon containing formation and blending the fluid with the blending agent to produce the mixture, wherein the part of the formation and the second part of the formation are located in different hydrocarbon containing formations.

6. The method of one or more of claims 1-3, further comprising producing the fluid from a second part of a hydrocarbon containing formation and blending the fluid with the blending agent to produce the mixture, wherein the part of the formation and the second part of the formation are located in different hydrocarbon containing formations, and wherein the different hydrocarbon containing formations are vertically displaced.

7. The method of one or more of claims 1-3, further comprising producing the fluid from a second part of a hydrocarbon containing formation and blending the fluid with the blending agent to produce the mixture, wherein the part of the formation and the second part of the formation are vertically displaced within a single hydrocarbon containing formation.

8. The method of one or more of claims 1-7, further comprising cold producing the fluid from a second part of a hydrocarbon containing formation.

9. The method of one or more of claims 1-8, further comprising injecting the blending agent into a second part hydrocarbon containing formation to produce the mixture in the hydrocarbon containing formation and/or to produce the mixture in a production well.

10. The method of one or more of claims 1-9, further comprising inhibiting production of at least a portion of the blending agent until at least some hydrocarbons in the part of the formation have been pyrolyzed.

11. The method of one or more of claims 1-10, further comprising determining a time that at least some hydrocarbons in the blending agent are subjected to pyrolysis temperatures in the formation using a laboratory treatment of formation samples and/or a simulation of treatment of the formation.

12. The method of one or more of claims 1-11, further comprising varying a location for producing the blending agent to produce a selected quality in the blending agent.

13. The method of one or more of claims 1-12, further comprising controlling a selected quality of the blending agent by controlling the heat provided from at least one of the heaters and or the pressure at a production well within the part of the formation.

14. The method of one or more of claims 1-13, further comprising maintaining a pressure in the part of the formation below 35 bars absolute.

15. The method of one or more of claims 1-14, wherein an average temperature within the part of the formation is below 375 °C.

16. The method of one or more of claims 1-15, further comprising producing the blending agent when a partial pressure of hydrogen in the part of the formation is at least about 0.5 bars absolute and/or from an upper portion of the formation.

17. The method of one or more of claims 1-16, wherein the heat provided from at least one heater is transferred to at least a portion of the formation substantially by conduction.

18. The method of one or more of claims 1-17, wherein the fluid has a high viscosity that inhibits economical transport over more than 100 km via a pipeline but the mixture has a reduced viscosity that permits economical transport over more than 100 km via a pipeline.

19. The method of one or more of claims 1-18, wherein the selected property of the mixture is created by blending the blending agent and fluid such that the mixture has a selected API gravity, a selected viscosity, a selected density, a selected asphaltene to saturated hydrocarbon ratio, a selected aromatic hydrocarbon to saturated hydrocarbon ratio, and/or a selected impurity level.

20. The method of one or more of claims 1-19, wherein the selected property of the mixture comprises an API gravity of greater than about 10°, a viscosity of less than about 7500 cs at about 4 °C, a density of less than about 1 g/cm³ at about 4 °C, an asphaltene to saturated hydrocarbon ratio of less than 1 or an aromatic hydrocarbon to saturated hydrocarbon ratio of less than 4.

21. The method of one or more of claims 1-20, wherein the blending agent comprises at least some pyrolyzed hydrocarbons.

22. The method of one or more of claims 1-21, further comprising selectively limiting a temperature proximate a selected portion of a heater well to inhibit coke formation proximate at or near the selected portion and producing a mixture of at least some hydrocarbons through the selected portion of the heater well.

23. A blending agent produced by the method of any one of claims 1 -22.

24. A mixture of the blending agent of claim 23 and a fluid, wherein asphaltenes are substantially stable in the mixture at ambient temperature.

25. A mixture of the blending agent of claim 23 and a fluid, wherein the mixture comprises equal to or less than about 20 % by weight of the blending agent.

26. The blending agent according to any one of claims 23-25, wherein the blending agent comprises an API gravity of at least about 15°.

27. A pumpable mixture produced by mixing the blending agent of any one of claims 23-25 with a viscous crude oil, wherein the blending agent is produced according to the method of any one of claims 1-22, and wherein the pumpable mixture has a selected property such as selected API gravity, a selected viscosity, a selected density, and/or a selected impurity.