Downhole burner wells for in situ conversion of organic-rich rock formations

מבערים לבארות בעומק הפיר עבור הפיבה ״תוך בארית״ של מופעי סלע עשיר בחומר אורגני

Downhole burner wells for IN SITU conversion of organic-rich rock formations

ExxonMobil Upstream Research Company C.195998

DOWNHOLE BURNER WELLS FOR IN SITU CONVERSIONOF ORGANIC-RICH ROCK FORMATIONS

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U.S. Provisional Patent Application Serial No. 5 60/930,311, filed May 15, 2007. That application is titled “Downhole Burner Wells for In Situ

Conversion of Organic-Rich Rock Formations,” and is incorporated herein in its entirety byreference.

[0002] This application is related to co-pending, concurrently filed, and commonly assignedU. S. Patent Application [Attorney Docket No. 2007EM025] entitled "Downhole Burners for In 10 Situ Conversion of Organic-Rich Rock Formations", which claims the benefit of U. S.Provisional Patent Application Serial No. 60/930,308, filed May 15, 2007, the disclosures ofwhich are hereby incorporated herein in their entirety by reference.

BACKGROUND OF THE INVENTION

Field of the Invention 15 [0003] The present invention relates to the field of hydrocarbon recovery from subsurface formations. More specifically, the present invention relates to the in situ recovery ofhydrocarbon fluids from organic-rich rock formations including, for example, oil shaleformations, coal formations and tar sands formations. The present invention also relates tomethods for heating a subsurface formation using combustion fuel. 20 Background of the Invention [0004] Certain geological formations are known to contain an organic matter known as“kerogen.” Kerogen is a solid, carbonaceous material. When kerogen is imbedded in rockformations, the mixture is referred to as oil shale. This is true whether or not the mineral is, infact, technically shale, that is, a rock formed from compacted clay. 25 [0005] Kerogen is subject to decomposing upon exposure to heat over a period of time.

Upon heating, kerogen molecularly decomposes to produce oil, gas, and carbonaceous coke.Small amounts of water may also be generated. The oil, gas and water fluids become mobilewithin the rock matrix, while the carbonaceous coke remains essentially immobile.

[0006] Oil shale formations are found in various areas world-wide, including the United30 States. Such formations are notably found in Wyoming, Colorado, and Utah. Oil shale

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formations tend to reside at relatively shallow depths and are often characterized by limitedpermeability. Some consider oil shale formations to be hydrocarbon deposits which have not yetexperienced the years of heat and pressure thought to be required to create conventional oil andgas reserves. 5 [0007] The decomposition rate of kerogen to produce mobile hydrocarbons is temperature dependent. Temperatures generally in excess of 270° C (518° F) over the course of many monthsmay be required for substantial conversion. At higher temperatures substantial conversion mayoccur within shorter times. When kerogen is heated to the necessary temperature, chemicalreactions break the larger molecules forming the solid kerogen into smaller molecules of oil and10 gas. The thermal conversion process is referred to as pyrolysis or retorting.

[0008] Attempts have been made for many years to extract oil from oil shale formations.Near-surface oil shales have been mined and retorted at the surface for over a century. In 1862,James Young began processing Scottish oil shales. The industry lasted for about 100 years.Commercial oil shale retorting through surface mining has been conducted in other countries as 15 well such as Australia, Brazil, China, Estonia, France, Russia, South Africa, Spain, and Sweden.However, the practice has been mostly discontinued in recent years because it proved to beuneconomical or because of environmental constraints on spent shale disposal. (See T.F. Yen,and G.V. Chilingarian, “Oil Shale," Amsterdam, Elsevier, p. 292, the entire disclosure of whichis incorporated herein by reference.) Further, surface retorting requires mining of the oil shale,20 which limits application to very shallow formations.

[0009] In the United States, the existence of oil shale deposits in northwestern Colorado hasbeen known since the early 1900’s. While research projects have been conducted in this areafrom time to time, no serious commercial development has been undertaken. Most research onoil shale production has been carried out in the latter half of the 1900’s. The majority of this 25 research was on oil shale geology, geochemistry, and retorting in surface facilities.

[0010] In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom. That patent, entitled “Methodof Treating Oil Shale and Recovery of Oil and Other Mineral Products Therefrom,” proposed theapplication of heat at high temperatures to the oil shale formation in situ. The purpose of such insitu heating was to distill hydrocarbons and produce them to the surface. The ‘195 Ljungstrom 30 patent is incorporated herein by reference.

[0011] Ljungstrom coined the phrase “heat supply channels” to describe bore holes drilledinto the formation. The bore holes received an electrical heat conductor which transferred heat to 3

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the surrounding oil shale. Thus, the heat supply channels served as early heat injection wells.The electrical heating elements in the heat injection wells were placed within sand or cement orother heat-conductive material to permit the heat injection wells to transmit heat into thesurrounding oil shale while preventing the inflow of fluid. According to Ljungstrom, the5 “aggregate” was heated to between 500° and 1,000° C in some applications.

[0012] Along with the heat injection wells, fluid producing wells were also completed in nearproximity to the heat injection wells. As kerogen was pyrolyzed upon heat conduction into therock matrix, the resulting oil and gas would be recovered through the adjacent production wells.

[0013] Ljungstrom applied his approach of thermal conduction from heated wellbores10 through the Swedish Shale Oil Company. A full scale plant was developed that operated from 1944 into the 1950's. (See G. Salamonsson, “The Ljungstrom In Situ Method for Shale-OilRecovery," 2nd Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute ofPetroleum, London, p. 260-280 (1951), the entire disclosure of which is incoiporated herein byreference.) 15 [0014] Additional in situ methods have been proposed. These methods generally involve the injection of heat and/or solvent into a subsurface oil shale formation. Heat may be in the form ofheated methane (see U.S. Pat. No. 3,241,611 to J.L. Dougan), flue gas, or superheated steam (seeU.S. Pat. No. 3,400,762 to D.W. Peacock). Heat may also be in the form of electric resistiveheating, dielectric heating, radio frequency (RF) heating (U.S. Pat. No. 4,140,180, assigned to the20 ΓΓΤ Research Institute in Chicago, Illinois) or oxidant injection to support in situ combustion. Insome instances, artificial permeability has been created in the matrix to aid the movement ofpyrolyzed fluids. Permeability generation methods include mining, rubblization, hydraulicfracturing (see U.S. Pat. No. 3,468,376 to M.L. Slusser and U.S. Pat. No. 3,513,914 to J. V.Vogel), explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, et al.), heat25 fracturing (see U.S. Pat. No. 3,284,281 to R.W. Thomas), and steam fracturing (see U.S. Pat. No.2,952,450 to H. Purre).

[0015] In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company, the entire disclosure ofwhich is incorporated herein by reference. That patent, entitled “Conductively Heating aSubterranean Oil Shale to Create Permeability and Subsequently Produce Oil,” declared that30 “[cjontrary to the implications of. prior teachings and beliefs. the presently describedconductive heating process is economically feasible for use even in a substantially impermeablesubterranean oil shale.” (col. 6, In. 5054&amp;#1470;). Despite this declaration, it is noted that few, if any, 4

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commercial in situ shale oil operations have occurred other than Ljungstrom’s enterprise. The‘118 patent proposed controlling the rate of heat conduction within the rock surrounding eachheat injection well to provide a uniform heat front.

[0016] Additional history behind oil shale retorting and shale oil recovery can be found in co-5 owned patent publication WO 2005/010320 entitled “Methods of Treating a SubterraneanFormation to Convert Organic Matter into Producible Hydrocarbons,” and in patent publicationWO 2005/045192 entitled “Hydrocarbon Recovery from Impermeable Oil Shales.” TheBackground and technical disclosures of these two patent publications are incorporated herein byreference. 10 [0017] A need exists for improved processes for the production of shale oil. In addition, a need exists for improved downhole burners for converting an organic-rich formation intohydrocarbon fluids.

SUMMARY OF THE INVENTION

[0018] In one embodiment, the invention includes a method for in situ heating of an organic-15 rich rock formation. The method includes providing a first wellbore extending at least to a depth of the organic-rich rock formation, and providing a second wellbore intersecting the firstwellbore. The method further includes injecting an oxidant and a first combustible fuel into thefirst wellbore and providing hardware in the first wellbore so as to cause the oxidant and the firstcombustible fuel to mix and to combust at substantially the depth of the organic-rich rock20 formation. In this way, first combustion products are formed. The method further includesflowing the first combustion products into and up the second wellbore such that (1) a first heatprofile is created from the first wellbore, and (2) a second heat profile is created from the secondwellbore. After flowing the first combustion products for a period of time, the first heat profilemates with the second heat profile. At the time of mating, this provides a substantially25 continuous pyrolysis zone of formation hydrocarbons located within a substantial portion of theorganic-rich rock formation between the first and second wellbores.

[0019] In one aspect, the formation hydrocarbons comprise heavy hydrocarbons. Preferably,the organic-rich rock formation is an oil shale formation and the formation hydrocarbonscomprise oil shale. 30 [0020] It is preferred that the combustion products are above a pyrolysis temperature in the second wellbore at or just below the approximate depth of the hardware in the first wellbore. 5

Alternatively or in addition, the combustion products fall below a pyrolysis temperature in thesecond wellbore at or just above the proximate depth of the hardware in the first wellbore. In oneaspect, at or near the end of flowing, the combustion products in the second wellbore are at atemperature of between 270° C and 360° C at a depth proximate to that of an upper depth of thehardware in the first wellbore.

[0021] The method may further include the steps of providing a casing string within the firstwellbore, and providing a casing string within the second wellbore.

[0022] In an alternate embodiment, the invention includes a method for in situ heating of atargeted organic-rich rock formation. The method may include providing a first wellboreextending at least to a depth of the targeted organic-rich rock formation, with the first wellborehaving a lower end. The method may further include providing a second wellbore also having alower end, the lower end of the second wellbore intersecting with the lower end of the firstwellbore to create fluid communication therebetween. The method may further include selectinga distance between the first wellbore and the second wellbore. The method may further includeproviding a burner in the first wellbore, and injecting an oxidant and a combustible fuel into thefirst wellbore and to the burner so as to combust the combustible fuel. The method may furtherinclude circulating flue gas generated from the burner in the first wellbore through the secondwellbore and to the surface. This serves to form (1) a first pyrolysis zone around the firstwellbore, and (2) a second pyrolysis zone around the second wellbore. The first pyrolysis zonemates with the second pyrolysis zone upon circulating the flue gas for a period of time.

[0023] In an alternate embodiment, the invention includes a heater well for the in situ heatingof a targeted organic-rich rock formation. The heater well may include a first wellbore extendingat least to a depth of the targeted organic-rich rock formation. The first wellbore has asubstantially vertical portion and a deviated portion defining a heel and a toe. The heater wellmay further include a substantially vertical second wellbore having a lower end, the lower end ofthe second wellbore intersecting with the toe of the first wellbore to create fluid communicationtherebetween. The heater well may further include at least one downhole combustion burnerwithin either the first or the second wellbore. A spacing is provided between the first wellboreand the second wellbore so that following the circulation of heated flue gas through the heaterwell for a period of time, a first pyrolysis zone from the first wellbore mates with a secondpyrolysis zone from the second wellbore in such a manner that (i) a substantially continuouspyrolysis zone of formation hydrocarbons is formed within a substantial portion of the organic-rich rock formation between the first and second wellbores, and (ii) the combustion products are WO 2008/143745 above a pyrolysis temperature in the second wellbore at or just below the approximate depth ofthe at least one combustion burner in the first wellbore, and fall below a pyrolysis temperature inthe second wellbore at or just above the approximate depth of the at least one combustion burnerin the first wellbore.

[0024] In an alternate embodiment, the invention includes a method of producing ahydrocarbon fluid. The method may include heating an organic-rich rock formation in situ usinga heater well, and producing a hydrocarbon fluid from the organic-rich rock formation. Thehydrocarbon fluid has been at least partially generated as a result of pyrolysis of formationhydrocarbons located in the organic-rich rock formation. The heater well may include a firstwellbore extending at least to a depth of the targeted organic-rich rock formation. The firstwellbore has a substantially vertical portion, and a lower deviated portion defining a heel and atoe. The heater well may further include a substantially vertical second wellbore having a lowerend, the lower end of the second wellbore intersecting with the toe of the first wellbore to createfluid communication therebetween. The heater well may also include at least one downholecombustion burner within either the first or the second wellbore.

[0025] . An alternate method of producing a hydrocarbon fluid is disclosed herein. Themethod may include providing a first wellbore extending at least to a depth of the organic-richrock formation, and providing a second wellbore intersecting the first wellbore. The method mayfurther include injecting an oxidant and a first combustible fuel into the first wellbore, andproviding hardware in the first wellbore so as to cause the oxidant and the first combustible fuelto mix and to combust at substantially the depth of the organic-rich rock formation. In this wayfirst combustion products are formed. The method may further include flowing the firstcombustion products into and up the second wellbore. A first heat profile is created from the firstwellbore, and a second heat profile is created from the second wellbore. The first and secondwellbores are spaced and configured so that following the circulation of heated flue gas for aperiod of time, a first pyrolysis zone from the first wellbore mates with a second pyrolysis zonefrom the second wellbore in such a manner that (i) a substantially continuous pyrolysis zone offormation hydrocarbons is formed within a substantial portion of the organic-rich rock formationbetween the first and second wellbores, and (ii) the combustion products are above a pyrolysistemperature in the second wellbore at or just below the approximate depth of the at least onecombustion burner in the first wellbore, and fall below a pyrolysis temperature in the secondwellbore at or just above the approximate depth of the at least one combustion burner in the firstwellbore. The method may further include producing a hydrocarbon fluid from the organic-rich

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rock formation, where the hydrocarbon fluid has been at least partially generated as a result ofpyrolysis of formation hydrocarbons located in the organic-rich rock formation.

' BRIEF DESCRIPTION OF THE DRAWINGS

[0026] So that the present invention can be better understood, certain drawings, graphs andflow charts are appended hereto. It is to be noted, however, that the drawings illustrate onlyselected embodiments of the inventions and are therefore not to be considered limiting of scope,for the inventions may admit to other equally effective embodiments and applications.

[0027] Figure 1 is a cross-sectional isometric view of an illustrative subsurface area. Thesubsurface area includes an organic-rich rock matrix that defines a subsurface formation.

[002B] Figure 2 is a flow chart demonstrating a general method of in situ thermal recovery ofoil and gas from an organic-rich rock formation, in one embodiment.

[0029] Figure 3 is a cross-sectional view of an illustrative oil shale formation that is within orconnected to groundwater aquifers and a formation leaching operation.

[0030] Figure 4 is a plan view of an illustrative heater well pattern, around a production well.Two layers of heater wells are shown.

[0031] Figure 5 is a bar chart comparing one ton of Green River oil shale before and after asimulated in situ, retorting process.

[0032] . Figure 6 is a process flow diagram of exemplary surface processing facilities for asubsurface formation development.

[0033] Figure 7 is a graph of the weight percent of each carbon number pseudo componentoccurring from C6 to C38 for laboratory experiments conducted at three different stress levels.

[0034] Figure 8 is a graph of the weight percent ratios of each carbon number pseudocomponent occurring from C6 to C38 as compared to the C20 pseudo component for laboratoryexperiments conducted at three different stress levels.

[0035] Figure 9 is a graph of the weight percent ratios of each carbon number pseudocomponent occurring from C6 to C38 as compared to the C25 pseudo component for laboratoryexperiments conducted at three different stress levels. 8

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[0036] Figure 10 is a graph of the weight percent ratios of each carbon number pseudocomponent occurring from C6 to C38 as compared to the C29 pseudo component for laboratoryexperiments conducted at three different stress levels.

[0037] Figure 11 is a graph of the weight percent of normal alkane hydrocarbon compounds5 occurring from normal&amp;#1470;C6 to normal-C38 for laboratory experiments conducted at three different stress levels.

[003B] Figure 12 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal-C6 to normal&amp;#1470;C38 as compared to the normal&amp;#1470;C20 hydrocarboncompound for laboratory experiments conducted at three different stress levels. 10 [0039] Figure 13 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 as compared to the normal-C25 hydrocarboncompound for laboratory experiments conducted at three different stress levels.

[0040] Figure 14 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal-C6 to normal-C38 as compared to the normal-C29 hydrocarbon15 compound for laboratory experiments conducted at three different stress levels. ,[0041] Figure 15 is a graph of the weight ratio of normal alkane hydrocarbon compounds topseudo components for each carbon number from C6 to C38 for laboratory experimentsconducted at three different stress levels.

[0042] Figure 16 is a bar graph showing the concentration, in molar percentage, of the20 hydrocarbon species present in the gas samples taken from duplicate laboratory experiments conducted at three different stress levels.

[0043] Figure 17 is an exemplary view of the gold tube apparatus used in the unstressed Parrheating test described below in Example 1.

[0044] Figure 18 is a cross-sectional view of the Parr vessel used in Examples 1-5, described25 below.

[0045] Figure 19 is gas chromatogram of gas sampled from Example 1.

Figure 20 is a whole oil gas chromatogram of liquid sampled from Example 1.

[0046] 9

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[0047] Figure 21 is an exemplary view of a Berea cylinder, Berea plugs, and an oil shale corespecimen as used in Examples 2-5.

[0048] Figure 22 is an exemplary view of the mini load frame and sample assembly used inExamples 2-5.

[0049] Figure 23 is gas chromatogram of gas sampled from Example 2.

[0050] Figure 24 is gas chromatogram of gas sampled from Example 3.

[0051] Figure 25 is a whole oil gas chromatogram of liquid sampled from Example 3.

[0052] Figure 26 is gas chromatogram of gas sampled from Example 4.

[0053] Figure 27 is a whole oil gas chromatogram of liquid sampled from Example 4.

[0054] Figure 28 is gas chromatogram of gas sampled from Example 5.

[0055] Figure 29A is a perspective view of a heater well of the present invention, in oneembodiment. The heater well includes at least one downhole burner. A profile of a pyrolysiszone around the heater well is indicated. 5 10 [0056] Figure 29B is a perspective view of the heater well of Figure 29A. Here, the pyrolysis15 zone is modified to demonstrate an undesirable heat profile.

[0057] Figure 29C is another perspective view of the heater well of Figure 29A. Here, thepyrolysis zone is modified to demonstrate a different undesirable heat profile.

[0058] Figure 30 is an enlarged cross-sectional view of the heater well of Figure 29A.

[0059] Figure 31 is a perspective, view of a plurality of heater wells of Figure 29A within a20 hydrocarbon development area.

[0060] Figure 32A is a side view of a row of three heater well arrangements from Figure29A, disposed in a plane. The three heater wells are placed generally end-to-end in order to heata formation along a desired direction. A poor pyrolysis zone is shown formed around the heaterwells.

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J 10 [0061] Figure 32B is another side view of a row of heater wells of Figure 29A, disposed in aplane. Here, a better pyrolysis zone is shown formed. The better pyrolysis zone producessmaller regions of underheating in comparison to the pyrolysis zone of Figure 32A.

[0062] Figure 33 is another perspective view of a plurality of heater wells of Figure 29A.The heater wells are in a large array within a hydrocarbon development area.

[0063] Figure 34 is a cross-sectional side view of a burner at the end of a tubular member. Acowl is seen adjacent the burner for mitigating heat.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions [0064] As used herein, the tenn ,&amp;#1523;hydrocarbon(s)" refers to organic material with molecularstructures containing carbon bonded to hydrogen. Hydrocarbons may also include otherelements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/orsulfur.

[0065] As used herein, the term "hydrocarbon fluids" refers to a hydrocarbon or mixtures ofhydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include ahydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, atprocessing conditions or at ambient conditions (15° C and 1 atm pressure). Hydrocarbon fluidsmay include, for example, oil, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysisgas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

[0066] As used herein, the terms "produced fluids" and "production fluids" refer to liquidsand/or gases removed from a subsurface formation, including, for example, an organic-rich rockformation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids.Production fluids may include, but are not limited to, pyrolyzed shale oil, synthesis gas, apyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids.

[0067] As used herein, the term "condensable hydrocarbons" means those hydrocarbons thatcondense at 25° C and one atmosphere absolute pressure. Condensable hydrocarbons mayinclude a mixture of hydrocarbons having carbon numbers greater than 4.

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[0068] As used herein, the term "non-condensable hydrocarbons" means those hydrocarbonsthat do not condense at 25° C and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

[0069] As used herein, the term "heavy hydrocarbons” refers to hydrocarbon fluids that are5 highly viscous at ambient conditions (15° C and 1 atm pressure). Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavyhydrocarbons 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 traceamounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally10 have an API gravity below about 20 degrees. Heavy oil, for example, generally has an APIgravity of about 10-20 degrees, whereas tar generally has an API gravity below about 10 degrees.The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15° C.

[0070] As used herein, the term "solid hydrocarbons" refers to any hydrocarbon material thatis found naturally in substantially solid form at formation conditions. Non-limiting examples 15 include kerogen, coal, shungites, asphaltites, and natural mineral waxes. [0071] As used herein, the term "formation hydrocarbons" refers to both heavy hydrocarbonsand solid hydrocarbons that are contained in an organic-rich rock formation. Formationhydrocarbons may be, but are not limited to, kerogen, oil shale, coal, bitumen, tar, naturalmineral waxes, and asphaltites. 20 [0072] As used herein, the term "tar” refers to a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally isgreater than 1.000. Tar may have an API gravity less than 10 degrees. ‘Tar sands” refers to aformation that has tar in it.

[0073] As used herein, the term "kerogen" refers to a solid, insoluble hydrocarbon that 25 principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Oil shale contains kerogen.

[0074] As used herein, the term "bitumen" refers to a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide.

[0075] As used herein, the term "oil" refers to a hydrocarbon fluid containing a mixture ofcondensable hydrocarbons. WO 2008/143745 [0076] As used herein, the term "subsurface" refers to geologic strata occurring below theearth's surface.

[0077] As used herein, the term “hydrocarbon-rich formation” refers to any formation thatcontains more than trace amounts of hydrocarbons. For example, a hydrocarbon-rich formation 5 may include portions that contain hydrocarbons at a level of greater than 5 volume percent. Thehydrocarbons located in a hydrocarbon-rich formation may include, for example, oil, natural gas,heavy hydrocarbons, and solid hydrocarbons.

[0078] As used herein, the term “organic-rich rock” refers to any rock matrix holding solidhydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but are not limited to, 10 sedimentary rocks, shales, siltstones, sands, silicilytes, carbonates, and diatomites.

[0079] As used herein, the term "formation” refers to any finite subsurface region. Theformation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any subsurface geologicformation. An "overburden" and/or an "underburden" is geological material above or below the . 15 formation of interest. An overburden or underburden may include one or more different types of .substantially impermeable materials. For example, overburden and/or underburden may includerock, shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonate withouthydrocarbons). An overburden and/or an underburden may include a hydrocarbon-containinglayer that is relatively impermeable. In some cases, the overburden and/or underburden may be20 permeable.

[0080] As used herein, the term “organic-rich rock formation” refers to any formationcontaining organic-rich rock. Organic-rich rock formations include, for example, oil shaleformations, coal formations, and tar sands formations.

[0081] As used herein, the term "pyrolysis" refers to the breaking of chemical bonds through25 the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone or by heat in combination with an oxidant. Pyrolysis mayinclude modifying the nature of the compound by addition of hydrogen atoms which may beobtained from molecular hydrogen, water, carbon dioxide, or carbon monoxide. Heat may betransferred to a section of the formation to cause pyrolysis. 30 [0082] As used herein, the term "water-soluble minerals" refers to minerals that are soluble in water. Water-soluble minerals include, for example, nahcolite (sodium bicarbonate), soda ash WO 2008/143745 (sodium carbonate), dawsonite (NaAl(C03)(OH)2), or combinations thereof. Substantialsolubility may require heated water and/or a non-neutral pH solution.

[0083] As used herein, the term "formation water-soluble minerals" refers to water-solubleminerals that are found naturally in a formation.

[0084] As used herein, the term "migratory contaminant species" refers to species that areboth soluble or moveable in water or an aqueous fluid, and are considered to be potentiallyharmful or of concern to human health or the environment. Migratory contaminant species mayinclude inorganic and organic contaminants. Organic contaminants may include saturatedhydrocarbons, aromatic hydrocarbons, and oxygenated hydrocarbons. Inorganic contaminantsmay include metal contaminants, and ionic contaminants of various types that may significantlyalter pH or the formation fluid chemistry. Aromatic hydrocarbons may include, for example,benzene, toluene, xylene, ethylbenzene, and tri-methylbenzene, and various types ofpolyaromatic hydrocarbons such as anthracenes, naphthalenes, chrysenes and pyrenes.Oxygenated hydrocarbons may include, for example, alcohols, ketones, phenols, and organicacids such as carboxylic acid. Metal contaminants may include, for example, arsenic, boron,chromium, cobalt, molybdenum, mercury, selenium, lead, vanadium, nickel or zinc. Ioniccontaminants include, for example, sulfides, sulfates, chlorides, fluorides, ammonia, nitrates,calcium, iron, magnesium, potassium, lithium, boron, and strontium.

[0085] As used herein, the term "sequestration" refers to the storing of a fluid that is a by-product of a process rather than discharging the fluid to the atmosphere or open environment.

[0086] As used herein, the term "subsidence" refers to a downward movement of a surfacerelative to an initial elevation of the surface.

[0087] As used herein, the term "thickness" of a layer refers to the distance between theupper and lower boundaries of a cross section of a layer, wherein the distance is measurednormal to the average tilt of the cross section.

[0088] As used herein, the term "thermal fracture" refers to fractures created in a formationcaused directly or indirectly by expansion or contraction of a portion of the formation and/orfluids within the formation, which in tum is caused by increasing/decreasing the temperature ofthe formation and/or fluids within the formation, and/or by increasing/decreasing a pressure offluids within the formation due to heating. Thermal fractures may propagate into or form inneighboring regions significantly cooler than the heated zone.

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[0089] As used herein, the term "hydraulic fracture" refers to a fracture at least partiallypropagated into a formation, wherein the fracture is created through injection of pressurizedfluids into the formation. The fracture may be artificially held open by injection of a proppantmaterial. Hydraulic fractures may be substantially horizontal in orientation, substantially vertical 5 in orientation, or oriented along any other plane.

[0090] As used herein, the term "wellbore" refers to a hole in the subsurface made by drillingor insertion of a conduit into the subsurface. A wellbore may have a substantially circular crosssection, or other cross-sectional shapes (e.g., circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes). As used herein, the term "well", when referring to an opening 10 in the formation, may be used interchangeably with the term "wellbore." [0091] As used herein, the term “cowl” means a tubular body of any material or constructionhaving perforations or vents therein.

[0092] As used herein, the term “targeted organic-rich rock formation” means a portion &amp;#1523;of anorganic-rich rock formation that has been chosen for heating. The chosen portion may be defined 15 according to a given depth or range of depths, a given horizontal distance, or both.

[0093] As used herein with respect to temperature and downhole burners, the term“substantially uniform” means that the temperature remains within a desired temperature rangeover a selected portion of an organic-rich rock formation.

[0094] As used herein, the terms “heat profile” means a region of a formation adjacent a20 source of heat that has been heated to greater than a specified temperature. For example, the specified temperature may be a minimum temperature at which pyrolysis begins to occur at aminimum desired rate.

[0095] The term “pyrolysis zone” means an area within a subsurface formation that hasreached a temperature wherein pyrolysis of formation hydrocarbons begins to occur. A pyrolysis 25 zone is associated with a heat profile.

[0096] As used herein, the term “mating” or “mates” means that a first heat profile expandsin such a way as to meet a second heat profile so that at the time of first merging, substantialportions of both the first and second heat profiles have reached a pyrolysis temperature.

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Description of Specific Embodiments [0097] The inventions are described herein in connection with certain specific embodiments.However, to the extent that the following detailed description is specific to a particularembodiment or a particular use, this is intended to be illustrative only, and is not to be construed 5 as limiting the scope of the invention.

[0098] As discussed herein, some embodiments of the invention include or have applicationrelated to an in situ method of recovering natural resources. The natural resources may berecovered from an organic-rich rock formation, including, for example, an oil shale formation.The organic-rich fock formation may include formation hydrocarbons, including, for example, 10 kerogen, coal, and heavy hydrocarbons. In some embodiments of the invention the naturalresources may include hydrocarbon fluids, including, for example, products of the pyrolysis offormation hydrocarbons such as shale oil. In some embodiments of the invention the naturalresources may also include water-soluble minerals, including, for example, nahcolite (sodiumbicarbonate, or 2NaHC03), soda ash (sodium carbonate, or Na2C03) and dawsonite15 (NaAl(C03)(0H)2).

[0099] Figure 1 presents a perspective view of an illustrative oil shale development area 10.A surface 12 of the development area 10 is indicated. Below the surface is an organic-rich rockformation 16. The illustrative subsurface formation 16 contains formation hydrocarbons (suchas, for example, kerogen) and possibly valuable water-soluble minerals (such as, for example, 20 nahcolite). It is understood that the representative formation 16 may be any organic-rich rockformation, including a rock matrix containing coal or tar sands, for example. In addition, therock matrix making up the formation 16 may be permeable, semi-permeable or non-permeable.The present inventions are particularly advantageous in oil shale development areas initiallyhaving very limited or effectively no fluid permeability. 25 [00100] In order to access formation 16 and recover natural resources therefrom, a plurality of wellbores is formed. Wellbores are shown at 14 in Figure 1. The representative wellbores 14are essentially vertical in orientation relative to the surface 12. However, it is understood thatsome or all of the wellbores 14 could deviate into an obtuse or even horizontal orientation. In thearrangement of Figure 1, each of the wellbores 14 is completed in the oil shale formation 16,30 The completions may be either open or cased hole. The well completions may also includepropped or unpropped hydraulic fractures emanating therefrom.

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[0101] In the view of Figure 1, only seven wellbores 14 are shown. However, it isunderstood that in an oil shale development project, numerous additional wellbores 14 will mostlikely be drilled. The wellbores 14 may be located in relatively close proximity, being from 10feet to up to 300 feet in separation. In some embodiments, a well spacing of 15 to 25 feet isprovided. Typically, the wellbores 14 are,also completed at shallow depths, being from 200 to5,000 feet at total depth. In some embodiments the oil shale formation targeted for in situretorting is at a depth greater than 200 feet below the surface or alternatively 400 feet below thesurface. Alternatively, conversion and production of a oil shale formation occurs at depthsbetween 500 and 2,500 feet.

[0102] The wellbores 14 will be selected for certain functions and may be designated as heatinjection wells, water injection wells, oil production wells and/or water-soluble mineral solutionproduction wells. In one aspect, the wellbores 14 are dimensioned to serve two, three, or all fourof these purposes. Suitable tools and equipment may be sequentially run into and removed fromthe wellbores 14 to serve the various purposes.

[0103] A fluid processing facility 17 is also shown schematically. The fluid processing facility17 is equipped to receive fluids produced from the organic-rich rock formation 16 through one or.more pipelines or flow lines 18. The fluid processing facility 17 may include equipment suitablefor receiving and separating oil, gas, and water produced from the heated formation. The fluidprocessing facility 17 may further include equipment for separating out dissolved water-solubleminerals and/or migratory contaminant species, including, for example, dissolved organiccontaminants, metal contaminants, or ionic contaminants in the produced water recovered fromthe organic-rich rock formation 16. The contaminants may include, for example, aromatichydrocarbons such as benzene, toluene, xylene, and tri-methylbenzene. The contaminants mayalso include polyaromatic hydrocarbons such as anthracene, naphthalene, chrysene and pyrene.Metal contaminants may include species containing arsenic, boron, chromium, mercury,selenium, lead, vanadium, nickel, cobalt, molybdenum, or zinc. Ionic contaminant species mayinclude, for example, sulfates, chlorides, fluorides, lithium, potassium, aluminum, ammonia, andnitrates.

[0104] In order to recover oil, gas, and sodium (or other) water-soluble minerals, a series of stepsmay be undertaken. Figure 2 presents a flow chart demonstrating a method of in situ thermalrecovery of oil and gas from an organic-rich rock formation 100, in one embodiment. It isunderstood that the order of some of the steps from Figure 2 may be changed, and that thesequence of steps is merely for illustration. 17 [0105] First, the oil shale (or other organic-rich rock) formation 16 is identified within thedevelopment area 10. This step is shown in box 110. Optionally, the oil shale formation maycontain nahcolite or other sodium minerals. The targeted development area within the oil shaleformation may be identified by measuring or modeling the depth, thickness and organic richnessof the oil shale as well as evaluating the position of the organic-rich rock formation relative toother rock types, structural features (e.g. faults, anticlines or synclines), or hydrogeological units(i.e. aquifers). This is accomplished by creating and interpreting maps and/or models of depth,thickness, organic richness and other data from available tests and sources. This may involveperforming geological surface surveys, studying outcrops, performing seismic surveys, and/ordrilling boreholes to obtain core samples from subsurface rock. Rock samples may be analyzedto assess kerogen content and hydrocarbon fluid generating capability.

[0106] The kerogen content of the organic-rich rock formation may be ascertained from outcropor core samples using a variety of data. Such data may include organic carbon content, hydrogenindex, and modified Fischer assay analyses. Subsurface permeability may also be asses$ed&amp;#1470;viarock samples, outcrops, or studies of ground water flow. Furthermore the connectivity of thedevelopment area to ground water sources may be assessed.

[0107] Next, a plurality of wellbores 14 is formed across the targeted development area 10. Thisstep is shown schematically in box 115. The purposes of the wellbores 14 are set forth above andneed not be repeated. However, it is noted that for purposes of the wellbore formation step ofbox 115, only a portion of the wells need be completed initially. For instance, at the beginning ofthe project heat injection wells are needed, while a majority of the hydrocarbon production wellsare not yet needed. Production wells may be brought in once conversion begins, such as after 4to 12 months of heating.

[0108] It is understood that petroleum engineers will develop a strategy for the best depth andarrangement for the wellbores 14, depending upon anticipated reservoir characteristics, economicconstraints, and work scheduling constraints. In addition, engineering staff will determine whatwellbores 14 shall be used for initial formation 16 heating. This selection step is represented bybox 120.

[0109] Concerning heat injection wells, there are various methods for applying heat to theorganic-rich rock formation 16. The present methods are not limited to the heating techniqueemployed unless specifically so stated in the claims. The heating step is represented generally by box 130. Preferably, for in situ processes the heating of a production zone takes place over aperiod of months, or even four or more years.

[0110] The formation 16 is heated to a temperature sufficient to pyrolyze at least a portion ofthe oil shale in order to convert the kerogen to hydrocarbon fluids. The bulk of the target zone of 5 the formation may be heated to between 270° C to 800° C. Alternatively, the targeted volume ofthe organic-rich formation is heated to at least 350° C to create production fluids. Theconversion step is represented in Figure 2 by box 135. The resulting liquids and hydrocarbongases may be refined into products which resemble common commercial petroleum products.Such liquid products include transportation fuels such as diesel, jet fuel and naphtha. Generated10 gases include light alkanes, light alkenes, ¾, C02, CO, and NH3.

[0111] Conversion of the oil shale will create permeability in the oil shale section in rocksthat were originally impermeable. Preferably, the heating and conversion processes of boxes 130and 135, occur over a lengthy period of time. In one aspect, the heating period is from threemonths to four or more years. Also as an optional part of box 135, the formation 16 may be 15 heated to a temperature sufficient to convert at least a portion of nahcolite, if present, to soda ash.Heat applied to mature the oil shale and recover oil and gas will also convert nahcolite to sodiumcarbonate (soda ash), a related sodium mineral. The process of converting nahcolite (sodiumbicarbonate) to soda ash (sodium carbonate) is described herein.

[0112] In connection with the heating step 130, the rock formation 16 may optionally be20 fractured to aid heat transfer or later hydrocarbon fluid production. The optional fracturing step is shown in box 125. Fracturing may be accomplished by creating thermal fractures within theformation through application of heat. By heating the organic-rich rock and transforming thekerogen to oil and gas, the permeability is increased via thermal fracture formation andsubsequent production of a portion of the hydrocarbon fluids generated from the kerogen.25 Alternatively, a process known as hydraulic fracturing may be used. Hydraulic fracturing is aprocess known in the art of oil and gas recovery where a fracture fluid is pressurized within thewellbore above the fracture pressure of the formation, thus developing fracture planes within theformation to relieve the pressure generated within the wellbore. Hydraulic fractures may be usedto create additional permeability in portions of the formation and/or be used to provide a planar30 source for heating. The WO 2005/010320 patent publication incorporated above describes oneuse of hydraulic fracturing.

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WO 2008/143745 PCTAJS2008/005008 19 [0113] As part of the hydrocarbon fluid production process 100, certain wells 14 may bedesignated as oil and gas production wells. This step is depicted by box 140. Oil and gasproduction might not be initiated until it is determined that the kerogen has been sufficientlyretorted to allow maximum recovery of oil and gas from the formation 16. In some instances, 5 dedicated production wells are not drilled until after heat injection wells (box 130) have been inoperation for a period of several weeks or months. Thus, box 140 may include the formation ofadditional wellbores 14. In other instances, selected heater wells are converted to productionwells.

[0114] After certain wellbores 14 have been designated as oil and gas production wells, oil10 and/or gas is produced from the wellbores 14. The oil and/or gas production process is shown at box 145. At this stage (box 145), any water-soluble minerals, such as nahcolite and convertedsoda ash may remain substantially trapped in the rock formation 16 as finely disseminatedcrystals or nodules within the oil shale beds, and are not produced. However, some nahcoliteand/or soda ash may be dissolved in the water created during heat conversion (box 135) within15 the formation. • [0115] Box 150 presents an optional next step in the oil and gas recovery method 100. Here, certain wellbores 14 are designated as water or aqueous fluid injection wells. Aqueous fluids aresolutions of water with other species; The water may constitute “brine,” and may includedissolved inorganic salts of chloride, sulfates and carbonates of Group I and Π elements of The20 Periodic Table of Elements. Organic salts can also be present in the aqueous fluid. The watermay alternatively be fresh water containing other species. The other species may be present toalter the pH. Alternatively, the other species may reflect the availability of brackish water notsaturated in the species wished to be leached from the subsurface. Preferably, the water injectionwells are selected from some or all of the wellbores used for heat injection or for oil and/or gas25 production. However, the scope of the step of box 150 may include the drilling of yet additionalwellbores 14 for use as dedicated water injection wells. In this respect, it may be desirable tocomplete water injection wells along a periphery of the development area 10 in order to create aboundary of high pressure.

[0116] Next, optionally water or an aqueous fluid is injected through the water injection30 wells and into the oil shale formation 16. This step is shown at box 155. The water may be inthe form of steam or pressurized hot water. Alternatively the injected water may be cool andbecomes heated as it contacts the previously heated formation. The injection process may furtherinduce fracturing. This process may create fingered caverns and brecciated zones in the # 20 nahcolite-bearing intervals some distance, for example up to 200 feet out, from the waterinjection wellbores. In one aspect, a gas cap, such as nitrogen, may be maintained at the top ofeach "cavern" to prevent vertical growth.

[0117] Along with the designation of certain wellbores 14 as water injection wells, the design5 engineers may also designate certain wellbores 14 as water or water-soluble mineral solution production wells. This step is shown in box 160. These wells may be the same as wells used topreviously produce hydrocarbons or inject heat. These recovery wells may be used to produce anaqueous solution of dissolved water-soluble minerals and other species, including, for example,migratory contaminant species. For example, the solution may be one primarily of dissolved10 soda ash. This step is shown in box 165. Alternatively, single wellbores may be used to bothinject water and then to recover a sodium mineral solution. Thus, box 165 includes the option ofusing the same wellbores 14 for both water injection and solution production (box 165).

[0118] Temporary control of the migration of the migratory contaminant species, especiallyduring the pyrolysis process, can be obtained via placement of the injection and production wells 15 14 such that fluid flow out of the heated zone is minimized. Typically, this involves placing injection wells at the periphery of the heated zone so as to cause pressure gradients which preventflow inside the heated zone from leaving the zone.

[0119] Figure 3 is a cross-sectional view of an illustrative oil shale formation that is withinor connected to ground water aquifers and a formation leaching operation. Four separate oil 20 shale formation zones are depicted (23, 24,25 and 26) within the oil shale formation. The wateraquifers are below the ground surface 27, and are categorized as an upper aquifer 20 and a loweraquifer 22. Intermediate the upper and lower aquifers is an aquitard 21. It can be seen thatcertain zones of the formation are both aquifers or aquitards and oil shale zones. A plurality ofwells (28, 29, 30 and 31) is shown traversing vertically downward through the aquifers. One of25 the wells is serving as a water injection well 31, while another is serving as a water productionwell 30. In this way, water is circulated 32 through at least the lower aquifer 22.

[0120] Figure 3 shows diagrammatically water circulating 32 through an oil shale volumethat was heated 33, that resides within or is connected to an aquifer 22, and from whichhydrocarbon fluids were previously recovered. Introduction of water via the water injection well30 31 forces water into the previously heated oil shale 33 so that water-soluble minerals and migratory contaminants species are swept to the water production well 30. The water may thenprocessed in a facility 34 wherein the water-soluble minerals (e.g., nahcolite or soda ash) and the migratory contaminants may be substantially removed from the water stream. Water is then re-injected into the oil shale volume 33 and the formation leaching is repeated. This leaching withwater is intended to continue until levels of migratory contaminant species are at environmentallyacceptable levels within the previously heated oil shale zone 33. This may require 1 cycle, 2cycles, 5 cycles 10 cycles or more cycles of formation leaching, where a single cycle indicatesinjection and production of approximately one pore volume of water. It is understood that theremay be numerous water injection and water production wells in an actual oil shale development.Moreover, the system may include monitoring wells (28 and 29) which can be utilized during theoil shale heating phase, the shale oil production phase, the leaching phase, or during anycombination of these phases to monitor for migratory contaminant species and/or water-solubleminerals.

[0121] In some fields, formation hydrocarbons, such as oil shale, may exist in more than onesubsurface formation. In some instances, the organic-rich rock formations may be separated byrock layers that are hydrocarbon-free or that otherwise have little or no commercial value.Therefore, it may be desirable for the operator of a field under hydrocarbon development toundertake an analysis as to which of the subsurface, organic-rich rock formations to target or inwhich order they should be developed.

[0122] The organic-rich rock formation may be selected for development based on variousfactors. One such factor is the thickness of the hydrocarbon containing layer within theformation. Greater pay zone thickness may indicate a greater potential volumetric production ofhydrocarbon fluids. Each of the hydrocarbon containing layers may have a thickness that variesdepending on, for example, conditions under which the formation hydrocarbon containing layerwas formed. Therefore, an organic-rich rock formation will typically be selected for treatment ifthat formation includes at least one formation hydrocarbon-containing layer having a thicknesssufficient for economical production of produced fluids.

[0123] An organic-rich rock formation may also be chosen if the thickness of several layersthat are closely spaced together is sufficient for economical production of produced fluids. Forexample, an in situ conversion process for formation hydrocarbons may include selecting andtreating a layer within an organic-rich rock formation having a thickness of greater than about 5meters, 10 meters, 50 meters, or even 100 meters. In this manner, heat losses (as a fraction oftotal injected heat) to layers formed above and below an organic-rich rock formation may be lessthan such heat losses from a thin layer of formation hydrocarbons. A process as described

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herein, however, may also include selecting and treating layers that may include layerssubstantially free of formation hydrocarbons or thin layers of formation hydrocarbons.

[0124] The richness of one or more organic-rich rock formations may also be considered.Richness may depend on many factors including the conditions under which the formationhydrocarbon containing layer was formed, an amount of formation hydrocarbons in the layer,and/or a composition of formation hydrocarbons in the layer. A thin and rich formationhydrocarbon layer may be able to produce significantly more valuable hydrocarbons than a muchthicker, less rich formation hydrocarbon layer. Of course, producing hydrocarbons from aformation that is both thick and rich is desirable.

[0125] The kerogen content of an organic-rich rock formation may be ascertained fromoutcrop or core samples using a variety of data. Such data may include organic carbon content,hydrogen index, and modified Fischer assay analyses. The Fischer Assay is a standard methodwhich involves heating a sample of a formation hydrocarbon containing layer to approximately500° C in one hour, collecting fluids produced from the heated sample, and quantifying theamount of fluids produced.

[0126] Subsurface formation permeability may also be assessed via rock samples, outcrops,or studies of ground water flow. Furthermore the connectivity of the development area to groundwater sources may be assessed. Thus, an organic-rich rock formation may be chosen fordevelopment based on the permeability or porosity of the formation matrix even if the thicknessof the formation is relatively thin.

[0127] Other factors known to petroleum engineers may be taken into consideration whenselecting a formation for development. Such factors include depth of the perceived pay zone,stratigraphic proximity of fresh ground water to kerogen-containing zones, continuity ofthickness, and other factors. For instance, the assessed fluid production content within aformation will also effect eventual volumetric production.

[0128] In producing hydrocarbon fluids from an oil shale field, it may be desirable to controlthe migration of pyrolyzed fluids. In some instances, this includes the use of injection wells,particularly around the periphery of the field. Such wells may inject water, steam, C02, heatedmethane, or other fluids to drive cracked kerogen fluids inwardly towards production wells. Insome embodiments, physical barriers may be placed around the area of the organic-rich rockformation under development. One example of a physical barrier involves the creation of freezewalls. Freeze walls are formed by circulating refrigerant through peripheral wells to substantially

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reduce the temperature of the rock formation. This, in turn, prevents the pyroly2ation of kerogenpresent at the periphery of the field and the outward migration of oil and gas. Freeze walls willalso cause native water in the formation along the periphery to freeze.

[0129] The use of subsurface freezing to stabilize poorly consolidated soils or to provide a5 barrier to fluid flow is known in the art. Shell Exploration and Production Company has discussed the use of freeze walls for oil shale production in several patents, including U.S. Pat.No. 6,880,633 and U.S. Pat. No. 7,032,660. Shell’s ‘660 patent uses subsurface freezing toprotect against groundwater flow and groundwater contamination during in situ shale oilproduction. Additional patents that disclose the use of so-called freeze walls are U.S. Pat. No.10 3,528,252, U.S. Pat. No. 3,943,722, U.S. Pat. No. 3,729,965, U.S. Pat. No. 4,358,222, U.S. Pat.

No. 4,607,488, and WO Pat. No. 98996480. &amp;#1512;&amp;#1470; [0130] As noted above, several different types of wells may be used in the development of anorganic-rich rock formation, including, for example, an oil shale field. For example, the heatingof the organic-rich rock formation may be accomplished through the use of heater wells. The 15 heater wells may include, for example, electrical resistance heating elements. The production ofhydrocarbon fluids from the formation may be accomplished through the use of wells completedfor the production of fluids. The injection of an aqueous fluid may be accomplished through theuse of injection wells. Finally, the production of an aqueous solution may be accomplishedthrough use of solution production wells. 20 [0131] The different wells listed above may be used for more than one purpose. Stated another way, wells initially completed for one purpose may later be used for another purpose,thereby lowering project costs and/or decreasing the time required to perform certain tasks. Forexample, one or more of the production wells may also be used as injection wells for laterinjecting water into the organic-rich rock formation. Alternatively, one or more of the production25 wells may also be used as solution production wells for later producing an aqueous solution fromthe organic-rich rock formation.

[0132] In other aspects, production wells (and in some circumstances heater wells) mayinitially be used as dewatering wells (e.g., before heating is begun and/or when heating is initiallystarted). In addition, in some circumstances dewatering wells can later be used as production30 wells (and in some circumstances heater wells). As such, the dewatering wells may be placedand/or designed so that such wells can be later used as production wells and/or heater wells. Theheater wells may be placed and/or designed so that such wells can be later used as production

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1 24

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wells and/or dewatering wells. The production wells may be placed and/or designed so that suchwells can be later used as dewatering wells and/or heater wells. Similarly, injection wells may bewells that initially were used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for other purposes. Similarly, monitoring5 wells may be wells that initially were used for other purposes (e.g., heating, production,dewatering, injection, etc.). Finally, monitoring wells may later be used for other purposes suchas water production.

[0133] The wellbores for the various wells may be located in relatively close proximity,being from 10 feet to up to 300 feet in separation. Alternatively, the wellbores may be spaced 10 from 30 to 200 feet, or 50 to 100 feet. Typically, the wellbores are also completed at shallowdepths, being from 200 to 5,000 feet at total depth. Alternatively, the wellbores may becompleted at depths from 1,000 to 4,000 feet, or 1,500 to 3,500 feet. In some embodiments, theoil shale formation targeted for in situ retorting is at a depth greater than 200 feet below thesurface. In alternative embodiments, the oil shale formation targeted for in situ retorting is at a15 depth greater than 500, 1,000, or 1,500 feet below the surface. In alternative embodiments, theoil shale formation targeted for in situ retorting is at a depth between 200 and 5,000 feet,alternatively between 1,000 and 4,000 feet, 1,200 and 3,700 feet, or 1,500 and 3,500 feet belowthe surface.

[0134] It is desirable to arrange the various wells for an oil shale field in a pre-planned20 pattern. For instance, heater wells may be arranged in a variety of patterns including, but not limited to triangles, squares, hexagons, and other polygons. The pattern may include a regularpolygon to promote uniform heating through at least the portion of the formation in which theheater wells are placed. The pattern may also be a line drive pattern. A line drive patterngenerally includes a first linear array of heater wells, a second linear array of heater wells, and a25 production well or a linear array of production wells between the first and second linear array ofheater wells. Interspersed among the heater wells are typically one or more production wells.The injection wells may likewise be disposed within a repetitive pattern of units, which may besimilar to or different from that used for the heater wells.

[0135] One method to reduce the number of wells is to use a single well as both a heater well30 and a production well. Reduction of the number of wells by using single wells for sequential purposes can reduce project costs. One or more monitoring wells may be disposed at selectedpoints in the field. The monitoring wells may be configured with one or more devices that

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measure a temperature, a pressure, and/or a property of a fluid in the wellbore. In someinstances, a heater well may also serve as a monitoring well, or otherwise be instrumented.

[0136] Another method for reducing the number of heater wells is to use well patterns.Regular patterns of heater wells equidistantly spaced from a production well may be used. Thepatterns may form equilateral triangular arrays, hexagonal arrays, or other array patterns. Thearrays of heater wells may be disposed such that a distance between each heater well is less thanabout 70 feet (21 meters). A portion of the formation may be heated with heater wells disposedsubstantially parallel to a boundary of the hydrocarbon formation.

[0137] In alternative embodiments, the array of heater wells may be disposed such that adistance between each heater well may be less than about 100 feet, or 50 feet, or 30 feet.Regardless of the arrangement of or distance between the heater wells, in certain embodiments, aratio of heater wells to production wells disposed within a organic-rich rock formation may begreater than about 5,8,10, 20, or more.

[0138] In one embodiment, individual production wells are surrounded by at most one layerof heater wells. This may include arrangements such as 5-spot, 7-spot, or 9&amp;#1470;spot arrays, withalternating rows of production and heater wells. In another embodiment, two layers of heaterwells may surround a production well, but with the heater wells staggered so that a clear pathwayexists for the majority of flow away from the further heater wells. Row and reservoirsimulations may be employed to assess, the pathways and temperature history of hydrocarbonfluids generated in situ as they migrate from their points of origin to production wells.

[0139] Figure 4 provides a plan view of an illustrative heater well arrangement using morethan one layer of heater wells. The heater well arrangement is used in connection with theproduction of hydrocarbons from a shale oil development area 400. In Figure 4, the heater wellarrangement employs a first layer of heater wells 410, surrounded by a second layer of heaterwells 420. The heater wells in the first layer 410 are referenced at 431, while the heater wells inthe second layer 420 are referenced at 432.

[0140] A production well 440 is shown central to the well layers 410 and 420. It is noted thatthe heater wells 432 in the second layer 420 of wells are offset from the heater wells 431 in thefirst layer 410 of wells, relative to the production well 440. The purpose is to provide a flowpathfor converted hydrocarbons that minimizes travel near a heater well in the first layer 410 ofheater wells. This, in turn, minimizes secondary cracking of hydrocarbons converted fromkerogen as hydrocarbons flow from the second layer of wells 420 to the production wells 440. 26 [0141! In the illustrative arrangement of Figure 4, the first layer 410 and the second layer420 each defines a 5-spot pattern. However, it is understood that other patterns may beemployed, such as 3-spot or 6-spot patterns. In any instance, a plurality of heater wells 431comprising a first layer of heater wells 410 is placed around a production well 440, with a second5 plurality of heater wells 432 comprising a second layer of heater wells 420 placed around the firstlayer 410.

[0142] The heater wells in the two layers also may be arranged such that the majority ofhydrocarbons generated by heat from each heater well 432 in the second layer 420 are able tomigrate to a production well 440 without passing substantially near a heater well 431 in the first 10 layer 410. The heater wells 431, 432 in the two layers 410, 420 further may be arranged suchthat the majority of hydrocarbons generated by heat from each heater well 432 in the secondlayer 420 are able to migrate to the production well 440 without passing through a zone ofsubstantially increasing formation temperature.

[0143] Another method for reducing the number of heater wells is to use well patterns that15 are elongated in a particular direction, particularly in a direction determined to provide the most efficient thermal conductivity. Heat convection may be affected by various factors such asbedding planes and stresses within the formation. For instance, heat convection may be moreefficient in the direction perpendicular to the least horizontal principal stress on the formation. Insome instanced, heat convection may be more efficient in the direction parallel to the least20 horizontal principal stress.

[0144] In connection with the development of a shale oil field, it may be desirable that theprogression of heat through the subsurface in accordance with steps 130 and 135 be uniform.However, for various reasons the heating and maturation of formation hydrocarbons in asubsurface formation may not proceed uniformly despite a regular arrangement of heater and 25 production wells. Heterogeneities in the oil shale properties and formation structure may causecertain local areas to be more or less productive. Moreover, formation fracturing which occursdue to the heating and maturation of the oil shale can lead to an uneven distribution of preferredpathways and, thus, increase flow to certain production wells and reduce flow to others. Unevenfluid maturation may be an undesirable condition since certain subsurface regions may receive30 more heat energy than necessary where other regions receive less than desired. This, in tum,leads to the uneven flow and recovery of production fluids. Produced oil quality, overallproduction rate, and/or ultimate recoveries may be reduced. WO 2008/143745 [0145] To detect uneven flow conditions, production and heater wells may be instrumentedwith sensors. Sensors may include equipment to measure temperature, pressure, flow rates,and/or compositional information. Data from these sensors can be processed via simple rules orinput to detailed simulations to reach decisions on how to adjust heater and production wells toimprove subsurface performance. Production well performance may be adjusted by controllingbackpressure or throttling on the well. Heater well performance may also be adjusted bycontrolling energy input. Sensor readings may also sometimes imply mechanical problems witha well or downhole equipment which requires repair, replacement, or abandonment.

[0146] In one embodiment, flow rate, compositional, temperature and/or pressure data areutilized from two or more wells as inputs to a computer algorithm to control heating rate and/orproduction rates. Unmeasured conditions at or in the neighborhood of the well are then estimatedand used to control the well. For example, in situ fracturing behavior and kerogen maturation areestimated based on thermal, flow, and compositional data from a set of wells. In anotherexample, well integrity is evaluated based on pressure data, well temperature data, and estimatedin situ stresses. In a related embodiment the number of sensors is reduced by equipping only asubset of the wells with instruments, and using the results to interpolate, calculate, or estimateconditions at uninstrumented wells. Certain wells may have only a limited set of sensors (e.g.,wellhead temperature and pressure only) where others have a much larger set of sensors (e.g.,wellhead temperature and pressure, bottomhole temperature and pressure, productioncomposition, flow rate, electrical signature, casing strain, etc.).

[0147] As noted above, there are various methods for applying heat to an organic-rich rockformation. For example, one method may include electrical resistance heaters disposed in awellbore or outside of a wellbore. One such method involves the use of electrical resistive j heating elements in a cased or uncased wellbore. Electrical resistance heating involves directlypassing electricity through a conductive material such that resistive losses cause it to heat theconductive material. Other heating methods include the use of downhole combustors, in situcombustion, radio-frequency (RF) electrical energy, or microwave energy. Still others includeinjecting a hot fluid into the oil shale formation to directly heat it. The hot fluid may or may notbe circulated.

[0148] One method for formation heating involves the use of electrical resistors in which anelectrical current is passed through a resistive material which dissipates the electrical energy asheat. This method is distinguished from dielectric heating in which a high-frequency oscillatingelectric current induces electrical currents in nearby materials and causes them to heat. The

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electric heater may include an insulated conductor, an elongated member disposed in theopening, and/or a conductor disposed in a conduit. An early patent disclosing the use ofelectrical resistance heaters to produce oil shale in situ is U.S. Pat. No. 1,666,488. The ‘488patent issued to Crawshaw in 1928. Since 1928, various designs for downhole electrical heaters5 have been proposed. Illustrative designs are presented in U.S. Pat. No. 1,701,884, U.S. Pat. No.3,376,403, U.S. Pat. No. 4,626,665, U.S. Pat. No. 4,704,514, and U.S. Pat. No. 6,023,554.

[0149! A review of application of electrical heating methods for heavy oil reservoirs is givenby R. Sierra and S.M. Farouq Ali, “Promising Progress in Field Application of ReservoirElectrical Heating Methods”, Society of Petroleum Engineers Paper 69709, 2001. The entire10 disclosure of this reference is hereby incorporated by reference.

[0150] Certain previous designs for in situ electrical resistance heaters utilized solid,continuous heating elements (e.g., metal wires or strips). However, such elements may lack thenecessary robustness for long-term, high temperature applications such as oil shale maturation.As the formation heats and the oil shale matures, significant expansion of the rock occurs. This15 leads to high stresses on wells intersecting the formation. These stresses can lead to bending andstretching of the wellbore pipe and internal components. Cementing (e.g., U.S. Pat. No.4,886,118) or packing (e.g., U.S. Pat. No. 2,732,195) a heating element in place may providesome protection against stresses, but some stresses may still be transmitted to the heatingelement. 20 [0151] As an alternative, international patent publication WO 2005/010320 teaches the use of electrically conductive fractures to heat the oil shale. A heating element is constructed byforming wellbores and then hydraulically fracturing the oil shale formation around the wellbores.The fractures are filled with an electrically conductive material which forms the heating element.Calcined petroleum coke is an exemplary suitable conductant material. Preferably, the fractures25 are created in a vertical orientation extending from horizontal wellbores. Electricity may beconducted through the conductive fractures from the heel to the toe of each well. The electricalcircuit may be completed by an additional horizontal well that intersects one or more of thevertical fractures near the toe to supply the opposite electrical polarity. The WO 2005/010320process creates an "in situ toaster” that artificially matures oil shale through the application of30 electric heat. Thermal conduction heats the oil shale to conversion temperatures in excess of300° C, causing artificial maturation.

J 29 [0152] International patent publication WO 2005/045192 teaches an alternative heatingmeans that employs the circulation of a heated fluid within an oil shale formation. In the processof WO 2005/045192, supercritical heated naphtha may be circulated through fractures in theformation. This means that the oil shale is heated by circulating a dense, hot hydrocarbon vaporthrough sets of closely-spaced hydraulic fractures. In one aspect, the fractures are horizontallyformed and conventionally propped. Fracture temperatures of 320° - 400° C are maintained forup to five to ten years. Vaporized naphtha may be the preferred heating medium due to its highvolumetric heat capacity, ready availability and relatively low degradation rate at the heatingtemperature. In the WO 2005/045192 process, as the kerogen matures, fluid pressure will drivethe generated oil to the heated fractures where it will be produced with the cycling hydrocarbonvapor.

[0153] The purpose for heating the organic-rich rock formation is to pyrolyze at least aportion of the solid formation hydrocarbons to create hydrocarbon fluids. The solid formationhydrocarbons may be pyrolyzed in situ by raising the organic-rich rock formation, (or zoneswithin the formation), to a pyrolyzation temperature. In certain embodiments, the temperature ofthe formation may be slowly raised through the pyrolysis temperature range. For example, an insitu conversion process may include heating at least a portion of the organic-rich rock formationto raise the average temperature of the zone above about 270° C at a rate less than a selectedamount (e.g., about 10° C, 5° C; 3° C, 1° C, 0.5° C, or 0. Γ C) per day. In a further embodiment,the portion may be heated such that an average temperature of the selected zone may be less thanabout 375° C or, in some embodiments, less than about 400° C. The formation may be heatedsuch 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 where pyrolyzation begins tooccur).

[0154] The pyrolysis temperature range may vary depending on the types of formationhydrocarbons within the formation, the heating methodology, and the distribution of heatingsources. For example, a pyrolysis temperature range may include temperatures between about270° C and about 900° C. Alternatively, the bulk of the target zone of the formation may beheated to between 300° to 600° C. In an alternative embodiment, a pyrolysis temperature rangemay include temperatures between about 270° C to about 500° C.

[0155] Preferably, for in situ processes the heating of a production zone takes place over aperiod of months, or even four or more years. Alternatively, the formation may be heated for oneto fifteen years, alternatively, 3 to 10 years, 1.5 to 7 years, or 2 to 5 years. The bulk of the target 30 zone of the formation may be heated to between 270° to 800° C. Preferably, the bulk of the targetzone of the formation is heated to between 300° to 600° C. Alternatively, the bulk of the targetzone is ultimately heated to a temperature below 400° C (752° F).

[0156] In certain embodiments of the methods of the present invention, downhole burnersmay be used to heat a targeted organic-rich rock formation. Downhole burners of variousdesigns have been discussed in the patent literature for use in oil shale and other largely solidhydrocarbon deposits. Examples include, in numerical order, U.S. Pat. No. 2,887,160; U.S. Pat.No. 2,847,071; U.S. Pat. No. 2,895,555; U.S. Pat. No. 3,095,031; U.S. Pat. No. 3,109,482; U.S.Pat. No. 3,127,936; U.S. Pat. No. 3,225,829; U.S. Pat. No. 3,241,615; U;S. Pat. No. 3,254,721;U.S. Pat. No. 5,255,742; and U.S. Pat. No. 5,899,269.

[0157] Downhole burners operate through the transport of a combustible fuel (typicallynatural gas) and an oxidant (typically air) to a subsurface position in a wellbore. The fuel andoxidant react downhole to generate heat. The combustion gases are removed (typically bytransport to the surface, but possibly via injection into the formation). Downhole burners may·utilize pipe-in-pipe arrangements to separately transport fuel and an oxidant downhole, and thento remove the flue gas back up to the surface. Some downhole burners generate a flame, whileothers may not.

[0158] In the context of heavy oil recovery, downhole burners have been used for steamgeneration. In downhole steam generation, a combustor in the well is used to boil co-injectedwater. The water is then released into the formation.

[0159] The use of downhole burners is an alternative to other downhole heating methodssuch as electrical resistance heating and radio-frequency heating. In principle, downhole heatingmethods can be more efficient than these electrical methods since the energy losses (typicallyabout 50%) associated with generating electricity from combustible fuels are avoided. Downholeburners also reduce infrastructure cost. In this respect, there is no need for an expensiveelectrical power plant and distribution system.

[0160J Downhole heating can also be more efficient than the circulation of surface-heatedfluids. This is especially true for deep targets since heat losses to the overburden can be largelyavoided.

[0161] Applications of downhole heat technology have been described in F.M. Smith, “ADown-Hole Burner - Versatile Tool for Well Heating,” 25lh Technical Conference on Petroleum

Production, Pennsylvania State University, pp 275-285 (Oct. 19-21, 1966); H. Brandt, W.G.Poynter, and J.D. Hummell, “Stimulating Heavy Oil Reservoirs with Downhole Air-GasBurners,” World Oil, pp. 91-95 (Sept. 1965); and C.I. DePriester and A.J. Pantaleo, “WellStimulation by Downhole Gas-Air Burner,” Journal of Petroleum Technology, pp. 1297-1302(Dec. 1963).

[0162] Various challenges are presented by the use of downhole burners for heating aformation. As a result, there have been few major field applications of downhole burners. Keydesign issues include temperature control and metallurgy limitations. In this respect, the flametemperature in a burner can overheat the tubular and burner hardware, causing them to fail viamelting, thermal stresses, loss of tensile strength, or creep. Certain stainless steels, typically withhigh chromium content, can tolerate temperatures up to about 700° C for extended periods. (See,for example, H.E. Boyer and T.L. Gall (eds.), Metals Handbook, Chapter 16: “Heat-ResistantMaterial”, American Society for Metals, (1985.)) Another drawback is that the flames generatedby the downhole burner can cause hot spots within the burner and in the formation surroundingthe burner. This is due to radiant heat transfer from the luminous portion of the flame. A typicalgas flame can produce temperatures up to about 1,650° C. Therefore, materials of constructionfor the burners must be sufficient to withstand the temperatures of these hot spots. Use ofrefractory metals or ceramics can help solve these problems, but typically at a higher cost.Ceramic materials with acceptable strength at temperatures in excess of 900° C axe preferred.These would include high alumina content ceramics. Other ceramics that may be useful includechrome oxide, zirconia oxide, and magnesium oxide-based ceramics.

[0163] Additionally, the flue gases generated by the downhole burner can be corrosive due toC02 and water content. This is particularly true if the water condenses. Use of alloy metals suchas stainless steels can be used to reduce this potential problem.

[0164] Heat transfer in a pipe-in-pipe arrangement for a downhole burner can also lead todifficulties. The down-going fuel and air will heat exchange with the up-going hot flue gases. Ina well there is minimal room for a high degree of insulation and, hence, significant heat transferis possible. This cross heat-exchange can cause significant heating of the air and fuel prior toentering the burner. This, in turn, can lead to significantly higher-than-expected flametemperatures. Cross heat-exchange can also heat the flue gas moving up past the burner. If theburner is near the top of the target formation, the flue gas thus transports otherwise useful heatinto the overburden where it is neither needed nor desired. Additionally, the cross heat-exchange WO 2008/143745 can limit the transport of heat downstream of the burner since the hot flue gases may rapidly loseheat energy to the rising cooler flue gases.

[0165] For downhole burner applications, heat transfer can occur in one of several ways.These include conduction, convection, and radiative methods. Radiative heat transfer can beparticularly strong for an open flame. Therefore, it is desirable to provide a heater well having adownhole burner that harnesses the heat of the burner and more uniformly distributes heat acrossa zone of interest. Further, it is desirable to provide a heater well arrangement that minimizescross heat-exchange. Still further, it is desirable to provide an array of heater wells that create amore uniform heat distribution across a selected subsurface formation.

[0166] In one embodiment the invention includes a method for in situ heating of an organic-rich rock formation. The method may include providing a first wellbore extending at least to adepth of the organic-rich rock formation, and providing a second wellbore intersecting the firstwellbore. A wellbore circuit is thereby formed that is suitable for providing fluid communicationbetween the first wellbore and the second wellbore. In some embodiments, the first wellboremay extend to a depth below the organic-rich rock formation. The method may include injectingan oxidant, for example air, and a first combustible fuel, for example a light hydrocarbon gas,into the first wellbore, and providing hardware in the first wellbore so as to cause the oxidant andthe first combustible fuel to mix and to combust at substantially the depth of the organic-richrock formation The combustion forms combustion products. The method may further includeflowing the combustion products into and up the second wellbore. In this way, (1) a first heatprofile is created from the first wellbore, and (2) a second heat profile is created from the secondwellbore. The combustion products flow for a period of time, causing the first heat profile tosubstantially mate with the second heat profile. Pyrolysis of formation hydrocarbons locatedwithin the organic-rich rock formation between the first and second wellbores takes place. Theformation hydrocarbons located in the organic-rich rock formation may include heavyhydrocarbons and/or solid hydrocarbons. Particular examples include coal, tar sands, or oilshale.

[0167] In one embodiment, the combustion products are at a temperature above a pyrolysistemperature, for example 270° C, in the second wellbore at or just below the approximate depthof the hardware in'the first wellbore. Thereafter, the combustion products may fall below apyrolysis temperature in the second wellbore at or just above the approximate depth of thehardware in the first wellbore. In some embodiments, the method may include monitoring thetemperature of the combustion products in the second wellbore. In some embodiments, the 33 method may include monitoring the temperature of the combustion products at a point in thecasing string within the second wellbore at approximately the depth of the first burner.

[0168] In one embodiment both the first and second wellbores include a casing string withinthe respective wellbores. In some embodiments the first wellbore and the second wellbore arespaced apart from about 20 feet to 100 feet. Alternatively, the first wellbore and the secondwellbore are spaced apart from about 20 feet to SO feet. In some embodiments, the first wellboreis completed horizontally, thereby defining a heel and a toe. In some embodiments, the secondwellbore is completed substantially vertically. In some embodiments, the second wellboreintersects the first wellbore at about the toe of the first wellbore.

[0169] As used herein, the term “heat profile” means the region of the formation surroundinga source of heat that has been heated to greater than a specified temperature. For example, thespecified temperature may be a minimum temperature at which pyrolysis occurs at a minimumdesired heating rate. In some embodiments, there is a first heat profile created from the firstwellbore, and a second heat profile created from the second wellbore. The first heat profile mayinclude a first region of the organic-rich rock formation around the first wellbore having atemperature greater than 270° C while the second heat profile may include a second region of theorganic-rich rock formation around the second wellbore having a temperature greater than 270°C, for example. For example, the first heat profile and second heat profile may each have atemperature between about 300° C and 900° C. Still further, the first heat profile and second heatprofile may have a temperature between about 400° C and 700° C. In these instances, the heatprofiles create pyrolysis zones.

[0170] The method may include mating the first heat profile with the second heat profile.Preferably, the method further includes mating a first pyrolysis zone associated with the first heatprofile with a second pyrolysis zone associated with the second heat profile. This may beaccomplished by selecting specific operational parameters such as burner intensity, combustionfuel composition, oxidant injection rate, combustion fuel injection rate, well· separation betweenthe first wellbore and the second wellbore, or combinations thereof.

[0171] The concept of “mating” the heat profiles means that a first heat profile expands insuch a way as to meet a second heat profile so that at the time of first meeting, substantialportions of both the first and second heat profiles have reached a pyrolysis temperature. In thisway, a substantial portion of organic-rich rock in the formation is pyrolyzed. Designing theheater well to accommodate mating provides various benefits to a pyrolysis operation. For WO 2008/143745 example, over time a more uniform temperature is created within the formation that is above apyrolysis temperature. This avoids areas within a plane defined between the two wellbores thatexperience significant overheating or underheating. Preferably, a temperature variance withinthis plane of less than 350° C is avoided. 5 [0172] As another benefit, convective heat loss to the overburden is minimized by having the temperature of the combustion gases in the upward-flowing second wellbore be at a minimumpractical pyrolysis temperature at the time such gases reach a depth approximately equal to thatof the burner in the first wellbore. Preferably, the flue gases traveling in the second wellboremaintain a temperature in the second wellbore at the depth of the first burner that is between 260°10 C and 360° C or, more preferably, that is between 275° C and 325° C.

[0173] In some embodiments, the hardware may include a tubular member residing withinthe casing string within the first wellbore and extending to a selected portion of the organic-richrock formation. The tubular member forms an annular region with the surrounding casing. Thehardware may further include a first burner connected to the tubular member at a first depth 15 within the organic-rich rock formation. The first burner may be placed near the top of a targetedzone within the organic-rich rock formation. For example, the first burner may be placed within50 meters of the top of a targeted zone within the organic-rich rock formation. Alternatively, thefirst burner may be placed within 20 meters of the top of the organic-rich rock formation. Thefirst burner may be ignited using electric resistive heating elements. Alternatively, the first20 burner may be ignited using a removable electrical heated element. Still further, the first burnermay be ignited by injecting a pyrophoric substance, for example triethylborane, into the first andsecond tubular members. In some embodiments, the first burner supplies about 50 to 250 kW ofthermal energy. In alternate embodiments, the first burner provides 0.5 to 3.0 kW per meter ofwell length in a zone within the organic-rich rock formation targeted for pyrolysis. In other25 embodiments, the hardware may further include a tubular cowl located immediately below theburner. In some embodiments, the hardware may include at least one fuel line for delivering theinjected combustible fuel to the burners. In cases that employ casing and a tubular member, themethod may include injecting the first combustible fuel into the tubular member and injecting theoxidant into the annular space around the tubular member. Alternatively, the locations of30 injection may be reversed.

[0174] As a result of practicing certain of the methods, combustion products will begenerated and circulated through the second wellbore. In this instance, embodiments of themethods may include collecting the combustion products and reusing such collected combustion 35 products as a portion of the fuel or oxidant for the same or a different heater well arrangement.For example, the method may include collecting the combustion products from the secondwellbore at the surface and separating the combustion products in order to reclaim at least a partof the first combustible fuel. Further, the method may include delivering the reclaimedcombustible fuel to a tank and thereafter delivering the reclaimed combustible fuel from the tankback into the first wellbore. Alternatively, and particularly in instances where combustionproducts contain oxygen, the method may include collecting the combustion products from thesecond wellbore at the surface and compressing the oxygen. The compressed oxygen is mixedwith compressed air; and the mixture thereafter delivered into the first wellbore as a portion ofthe injected oxidant.

[0175] Whether the combustion products are collected and reused as a portion of the oxidantor as a portion of the combustible fuel, such collected combustion products may be used in adifferent well than the well from which they were collected. This process may be completed inyet additional heater wells. Alternatively, the method may include venting the combustionproducts to the atmosphere. Before the combustion products are vented to the atmosphere, theymay be treated to remove NOx components. In any of these cases, the combustion products maybe monitored for the presence of combustible species and/or excess air, thereby assessingwhether the burner is firing properly. In some embodiments, the combustible species mayinclude at least one of methane, ethane, hydrogen (H2), and carbon monoxide.

[0176] In the various embodiments, the oxidant and the combustible fuel may be delivered tothe burner in different ratios and at different rates. In one embodiment, the oxidant may beinjected in stoichiometric combustion excess at a mass rate of. 1.25 to 6.0 times the stoichiometriccombustion amount. In some embodiments, the oxidant is 02-enriched air. In someembodiments, the oxidant may be injected at a rate of about 10,000 to 50,000 kg/day oralternatively the oxidant may be injected at a rate of about 10,000 to 25,000 kg/day. In someembodiments, the oxidant may be injected under a pressure of about 50 to 250 psia. In someembodiments, the combustible fuel may injected under a pressure of greater than about 200 psia;alternatively, the combustible fuel may injected under a pressure of greater than about 600 psia.In some embodiments, at least a portion of the combustible fuel is derived from the gaseousportion of hydrocarbon fluids produced from pyrolyzed oil shale. Alternatively, at least a portionof the combustible fuel is comprised of a pipeline fuel gas. In either case, the combustible fuelmay include inert components or inert components. For example, carbon dioxide (C02) or 36 nitrogen (N2) may be added to the combustible fuel to adjust the composition of the combustiblefuel.

[0177] In the various described embodiments, the fluid flows within and the roles of the firstand second wellbores may be reversed. For example, the inlet and outlet roles of the first andsecond wellbores may be reversed after the targeted organic-rich rock formation has been heatedadjacent the first wellbore above the heel and towards the toe of the first wellbore. Thereafter, asecond burner and tubular member may be provided in the second wellbore and a second oxidantand a second combustible fuel may be injected into the second wellbore and through the secondburner so as to combust the second combustible fuel and to further heat the targeted organic-richrock formation adjacent the second wellbore and towards the heel of the first wellbore. Flue gasor combustible products generated from the second burner in the second wellbore may then becirculated through the first wellbore and to the surface.

[0178] In the various embodiments, multiple heater well arrangements may be provided toheat larger portions of the organic-rich rock formation. For example, the first wellbore, thesecond wellbore, and the burner may be thought of as defining a first heater well. Furtheradditional heater wells, each of which also comprises a first wellbore, a second wellbore, and aburner within the first wellbore, may be provided and arranged such that the respective firstwellbores and the respective second wellbores are in alternating relation, thereby alternating theportion of each heater well arrangement that contains the burner.

[0179] Figure 29A is a perspective view of a heater well 2900 of the present invention, inone embodiment. The heater well 2900 generally comprises a first wellbore 2902 that serves as agas input wellbore, and a second wellbore 2906 that serves as a gas output wellbore. One of thewellbores 2902 or 2906 has a horizontal portion 2904. In the illustrative embodiment of Figure29A, the first wellbore 2902 is deviated to provide the horizontal portion 2904. However, it iswithin the scope of the present disclosure for the second wellbore 2906 to be horizontallydeviated instead of the first wellbore 2902. Alternatively, the two wellbores 2902, 2906 may beconnected in a manner where each wellbore has a deviated section and where neither deviatedsection is fully horizontal.

[0180] The first wellbore 2902 has a lower end that is shown at 2901. The lower end 2901defines a “heel” for the horizontal portion 2904 of the wellbore 2902. The first wellbore 2902also has a “toe” 2903. The toe 2903 represents the end of the horizontal portion 2904 within thetargeted formation 300. The second wellbore 2906 also has a lower end. The lower end l 37 intersects the toe 2903 of the first wellbore 2902. In this way, fluid communication between thefirst 2902 and second 2906 wellbores is established.

[0181] Arrows “I" (for “input”) and “O” (for “output") are indicated for the movement ofgases through the wellbores 2902, 2906. In the embodiment of Figure 29A, the first wellbore2902 receives an oxidant and a combustible fuel gas (together “I,”), while the second wellbore2906 delivers combustion products (“O”). However, this role again may be reversed.

[0182] The purpose of the heater well 2900 is to generate a substantially continuous pyrolysiszone 2908A within a substantial portion of a targeted organic-rich rock formation 300. Morespecifically, the purpose is to heat a portion of the formation 300 to a temperature that issufficient to pyrolyze solid hydrocarbons such as kerogen into hydrocarbon fluids. In the presentinvention, this is done through the use of combustive heat that is conductively transferred to theformation 300. Air (or other oxidant) and a combustible fuel are injected into the first wellbore2902. The air and combustible fuel are mixed at a downhole burner 2905, where the fuelcombusts and forms into a flame. Flue gases, which may contain excess air or fuel, flow beyondthe burner 2905, down the first wellbore 2902, through the horizontal portion 2904, and back up.to the surface via the second wellbore 2906. The flue gases (including any excess air or fuel)represent combustion products.

[0183] The formation 300 in Figure 29A represents an organic-rich rock formation. Theorganic-rich rock formation may comprise tar sands, coal, oil shale, or other rock containingsolid hydrocarbons. Preferably, the organic-rich rock formation 300 is an oil shale formationcontaining kerogen. The burner 2905 is positioned to provide heat to a selected subsurfaceregion that comprises the kerogen.

[0184] It is desirable that the heater well 2900 uniformly distributes heat across a zone ofinterest downhole. The heating of regions above the desired temperature as might be done forrapid pyrolysis reflects an inefficient use of heating energy. Reciprocally, heating more slowlymeans that regions of the formation 300 will not reach the temperature needed for pyrolysis in areasonable amount of time, representing both an inefficient use of heating energy and a lostresource opportunity. This presents a challenge with downhole burners because of the intenseheat generated immediately at the depth of the burner 2905, followed by rapid cooling ascombustion products are circulated in the well. Stated another way, the hot flue gases reduce intemperature as they travel from the burner and along the well, giving up heat to the formation.Moreover, the conventional pipe-in-pipe downhole burner creates undesirable cross heat- 38 exchange above the burner 2905. The heater well 2900 seeks to overcome these challenges tocreate a uniform pyrolysis zone 2908A within the formation 300.

[0185] Figure 29A shows a snapshot of the pyrolysis zone 2908A around the heater well2900 at a specific time during formation heating. The pyrolysis zone 2908A may be defined asthe region having a temperature greater than a specific value required for reasonably rapidpyrolysis. For example, the value may be 250°C, 270°C, 300°C, 350°C, or some higher value. Itcan be seen that the pyrolysis zone 2908A expands away from the first wellbore 2902 faster atdepths closer to the burner 2905. The pyrolysis zone 2908A expands slower further down thewell as the combustion products move through the deviated portion 2904 and into the secondwellbore 2906. However, thermal conduction continues to take place into the formation 300even from the second wellbore 2906.

[0186] The utility of circulating a heated gas through the wellbores 2902, 2906 is the abilityto create a “mate” or “fit” between heat profiles emanating from the first 2902 and second 2906wellbores. The illustrative pyrolysis zone 2908A of Figure 29A provides a good “fit” becausethe faster heat front emanating from the first wellbore 2902 meets the slower heat frontemanating from the second wellbore 2906 roughly simultaneously. This means that there are fewif any areas of significant overheating or underheating within the formation 300 at the end of theheating process. In Figure 29A, only a small area of underheating 301 exists in the pyrolysiszone 2908A. Even this area 301 should be closed off over a modest amount of time as thermalconduction continues.

[0187] It is also noted from Figure 29A that the pyrolysis zone 2908A is formed by heatprofiles emanating from the first 2902 and second 2906 wellbores. Heat from combustionproducts flowing through the first wellbore 2902 creates a first heat profile 2912A, while heatfrom combustion products flowing through the second wellbore 2906 creates a second heatprofile 2916A. The second heat profile 2916A terminates, that is, no longer comprises apyrolysis temperature, up to an approximate depth of the burner 2905 in the first wellbore. Inthis way, excess combustion fuel is not employed.

[0188] Figures 29B and 29C provide contrasts to Figure 29A. Each of Figures 29B and29C show the heater well 2900 of Figure 29A. However, a different pyrolysis zone 2908B or2908C is generated from the first 2902 and second 2906 wellbores. 39 [0189] Concerning Figure 29B, in pyrolysis zone 2908B heat emanates from the firstwellbore 2902 too aggressively due to rapid heating immediately below the burner 2905. At thesame time, insufficient heat emanates from the second wellbore 2906 due to excess cooling of theflue gases as they travel into the deviated portion 2904 of the first wellbore 2902. Thus, thepyrolysis zone 2908B does not form a good fit for the heater well 2900 resulting in unevenheating within the formation 300. Further, a large area of underheating 301 exists.

[0190] It is seen in Figure 29B that the pyrolysis zone 2908B is formed by a heat profileemanating solely from, the first wellbore 2902. Heat from combustion products flowing throughthe first wellbore 2902 creates a first heat profile 2912B. However, heat from combustionproducts flowing through the second wellbore 2906 does not create a true heat profile aspyrolysis temperatures are not reached within the formation 300. This undesirable scenario maybe the product of a variety of factors. These include a mass flow rate of oxidant and/orcombustible fuel that is too low, a separation between the first 2902 and second 2904 burner,wells that is too great, a burner intensity that is too low, a burner position that is too high relativeto the horizontal portion 2904 of the first wellbore 2902, or a fuel composition too heavilyconcentrated with light hydrocarbons.

[0191] . Concerning Figure 29C, in pyrolysis zone 2908C heat emanates from the firstwellbore 2902 as a first heat profile 2912C, and from the second wellbore 2906 as a second heatprofile 2916C. However, the second heat profile 2916C extends too high, that is, it continuesabove the depth of the burner 2905 in the first wellbore 2902. As a result, the pyrolysis zone2908C does not form a good fit for the heater well 2900, causing heating outside of the formation300. While continued heating should prevent any significant areas of underheating in theformation 300, excess heating is taking place at depths higher than the formation 300.

[0192] It is also noted from Figure 29C that the pyrolysis zone 2908C is formed by the heatprofiles 2912C, 2916C emanating from the first 2902 and second 2906 wellbores. Heat fromcombustion products flowing through the first wellbore 2902 creates the first heat profile 2912C,while heat from combustion products flowing through the second wellbore 2906 creates thesecond heat profile 2916C. Of concern, however, excess heating is taking place at depths alongthe second wellbore 2906 higher than the depth of the burner 2905 in the first wellbore 2902.This undesirable scenario may be the product of a variety of factors including a mass flow rate ofoxidant and/or combustible fuel that is too high, a separation between the first 2902 and second2904 burner wells that is too small, a burner intensity that is too high, a burner position that is too 40 low relative to the horizontal portion 2904 of the first wellbore 2902, or a fuel composition toolightly concentrated with light hydrocarbons.

[0193] In order to correct the poor fit of pyrolysis zones 2908B or 2908C and form the moreappropriate fit of pyrolysis zone 2908A, various factors may be taken into account whendesigning the wellbore 2900. Such factors may include the distance “d” between the twowellbores 2902,2906, the intensity of the burner 2905, the position or depth of the burner 2905within the first wellbore 2902, fuel composition, amount of excess air or fuel injected, andformation thermal conductivity.

[0194] To provide a best fit for the pyrolysis zone, that is, to make the pyrolysis zone lookmore like zone 2908A, it is desirable that the combustion products (represented by “O”) in thesecond wellbore 2906 be above a pyrolysis temperature up to an approximate depth of thehardware 2905 in the first wellbore 2902. It is also desirable that the combustion products “O” inthe second wellbore 2906 fall below a pyrolysis temperature at Or just above the depth of thehardware 2905 in the first wellbore 2902. It is also preferred that the spacing “d” between thetwo wellbores 2902, 2906 be far enough away to prevent overheating of the formation 300, butclose enough to prevent underheating. In one aspect, the spacing is approximately 20 to 100 feet(about 6 to 30 meters). More preferably, the spacing “d” between the two wellbores 2902, 2906is approximately 30 to 80 feet (about 9 to 24 meters).

[0195] Figure 30 provides an enlarged side view of the heater well 2900 of Figure 29A.Once again, the first wellbore 2902 and the second wellbore 2906 are seen. The intermediatehorizontal portion 2904 of the first wellbore 2902 is also provided. Each of the wellbores 2902and 2906 is preferably cased. The exception is at the toe 2903 where the connection between thewellbore 2902, 2906 is made. In that instance, an arrangement of packers 2907 is preferablyprovided to seal the toe 2903 region. Casing strings 302,306 are provided for the first 2902 andsecond 2906 wellbores, respectively.

[0196] In order to generate heat through the downhole burner 2905, air as indicated by arrow“A” and a combustible fuel, indicated by arrow “CF,” are injected into the first wellbore 2902.Λ tubular member 305 is provided internal to the casing 302 in the first wellbore 2902. Anannulus 308 is formed between the tubing 305 and the surrounding casing 302. In one aspect, air“A” is injected into the annulus 308, while combustible fuel “CF” is injected into the tubing 305.In another aspect, fuel “CF” is injected into the annulus 308, while air “A” is injected into thetubing 305. WO 2008/143745 PCT7US2008/005008 41 [0197] Various ways may be provided for igniting the combustible fuel “CF’. For instance,the burner 2905 may be ignited using electrically resistive heating elements in the wellbore 2902.In one aspect, the resistive heating elements are removable electrical heating elements which canbe selectively inserted into the first wellbore 2902. In another aspect, the burner 2905 is ignitedby injecting a pyrophoric substance into the tubing 305. The pyrophoric substance may be eithera liquid or a solid substance.

[0198] Once the combustible fuel “CF” is ignited and a flame is generated, hot flue gases asindicated by arrow “FG are pushed down the first wellbore 2902 and through the horizontalportion 2904. This causes the formation 300 around the first wellbore 2902 and its horizontalportion 2904 to be heated by thermal conduction. The formation 300 around the second wellbore2906 is also heated by thermal conduction as flue gases “FG” are circulated through the heaterwell 2900.

[0199] The flue gases “FG” ” may include air “A.” The excess air “A”, if any, is pushedthrough the second wellbore 2906, and exits to the surface as indicated by arrow “0.” Theheated mixture of air “A” and combustible fuel “CF’ is together indicated by arrow “FG,” butmay also be generally referred to as “combustion products.” [0200] Returning to Figure 29A, it is again noted that a thermal profile, or “pyrolysis zone”2908A is shown. The pyrolysis zone 2908A represents the extent of heating provided into thetargeted organic-rich rock formation 300 by the combustion of fuel “CF’ and the circulation ofhot flue gas “FG.” The profile 2908A extends further out into the formation 300 proximate theburner 2905, and gradually diminishes as the flue gas “FG” travels through the horizontal portion2904 and up the second wellbore 2906.

[0201] Since the purpose of the heating exercise is to pyrolyze solid hydrocarbons within theformation 300, it is desirable that a temperature in excess of 270° C be provided to the formation300 between the first 2902 and the second 2906 wellbores. Thus, the pyrolysis zone 2908Arepresents heat being conducted from the first 2902 and second 2906 wellbores and into theformation 300 for the purposes of pyrolyzing rock in the formation 300 into hydrocarbon fluids.As noted, the pyrolysis zone 2908A has an underheated region 301, but this area 301 shouldclose as well as additional heating takes place over time.

[0202] Figure 29B shows a poor distribution of heat resulting in a substantial underheatedregion 301. In order to avoid the creation of the underheated region 301, several approaches maybe taken. A first approach is to reduce the distance “d” between the first 2902 and second 2906 42 wellbores. Preferably, the distance “d” is at least 10 meters to 30 meters. However, reducing thedistance “d” means that more heater wells 2900 are required. Moreover, reducing well spacingmay cause a significant volume to become needlessly overheated due to overlapping of thepyrolysis zones from the two wellbores 2902, 2906. Therefore, it is desired that the heat frontsemanating from the wellbores 2902, 2906 be controlled so that they fit together well or matewhen they approach each other.

[0203] A second approach is to reverse the direction of gas input as between the first 2902and the second 2906 wellbores after a period of time. This enables the heat profiles (such as2912A and 2916A of Figure 29A) to be reversed, meaning that the pyrolysis zone 2908Abecomes larger from the second wellbore 2906 than from the first wellbore 2902. In this way theentire formation 300 is more evenly heated. In connection with this second approach, it ispossible to reverse the direction of gas input “I” more than once. However, reversing thedirection of gas input “I” typically requires that the burner 2905 be pulled and the injectionequipment be moved from the first wellbore 2902 to the second wellbore 2906 each time.

[0204] Another approach is to move the burner 2905 incrementally down the first wellbore2902. In one aspect, the burner 2905 is initially near the top of the formation 300. The burnermay then be moved to a position just above the heel 2901 of the wellbore 2902. Subsequently,the burner 2905 may be moved beyond the heel 2901 into the horizontal portion 2904 of the firstwellbore 2902. In this way, different portions of the formation 300 receive the higher thermalenergy afforded by proximity to the burner 2905. However, this again requires the periodicmovement of the burner 2905.

[0205] A fourth approach is to set up a plurality of adjacent heater wells 2900. Figure 31provides a perspective view of a plurality of heater wells 2900 of Figure 29A within ahydrocarbon development area 3100. An array 2900’ of heater wells 2900 is provided. In thearray 2900’, the heater wells 2900 are aligned side-by-side. However, they are turned in 180°relation to one another. This is indicated in Figure 31 by the arrows “I” and “O,” which are seento be alternating.

[0206] It is noted from the array 2900’ that the burners 2905 are also alternating. The resultis that a heat front (not shown) originates more aggressively from the respective first wellbores2902 than from the adjacent second wellbores 2906. A fit or “mating” of the heat fronts thus notonly takes place between wellbores 2902, 2906 associated with each respective heater well 2900,but also between wellbores 2902,2906 in adjoining heater wells 2900. 43 [0207] In establishing an array of heater wells 2900’, the same design considerations as listedabove must be taken into account. These include the distance between the two wellbores 2902,2906, the intensity of the burners 2905, the position or depth of the burners 2905 within the firstwellbore 2902, fuel composition, amount of excess air or fuel injected, and formation thermalconductivity. In addition, consideration should be given as to the spacing between wellbores2902,2906 associated with adjacent heater wells 2900. This is demonstrated in Figures 32A and32B.

[0208] Figure 32A is a side view of three co-planar heater wells 2900 from Figure 29A.The three heater wells 2900 are placed generally end-to-end in order to heat a formation 300along a desired direction. This is different from the array 2900’ of Figures 31 where the heaterwells 2900 are side-by-side. Of course, in operation the field designer will create an array thatplaces heater wells 2900 both side-by-side and end-to-end.

[0209] In the wells 2900 of Figure 32A, a burner 2905 is seen within each of the firstwellbores 2902. The burners 2905 are used to cause heat to emanate from the wells 2900,thereby conductively forming a pyrolysis zone. A pyrolysis zone is seen at 3208A.

[0210] A profile of the pyrolysis zone 3208A is seen around each heater well 2900. This is a“snapshot" of the zone 3208A taken as a result of a heating process. It can be seen that thepyrolysis zone 3208A creates a poor heat front across the formation 300. The pyrolysis zone3208A includes undesirable regions of overheating and underheating. Regions of overheatingare shown at 3212, while regions of underheating are shown at 3214. The overheated 3212 andunderheated 3214 regions are a result of a placement of the burners 2905 too high in the firstwellbore 2902, and/or placing the wells 2900 too closely together, and/or having a burnerintensity that is too high.

[0211] It is acknowledged that as heating continues in the formation 300, the regions ofunderheating 3214 will eventually be heated and pyrolysis of formation hydrocarbons within theformation 300 will occur. However, at the same time the regions of overheating 3212 willundesirably grow. Thus, a poor fit of heat profiles will still result.

[0212] Figure 32B is another side view of a series of co-planar heater wells 2900 of Figure29A. Here, a pyrolysis zone 3208B is formed as a result of heating from downhole burners 3205.In this instance a more uniform heat front is formed across the formation 300. There is no regionof overheating 3212 as seen in Figure 32A. Only a very small region of underheating 3214 isleft between the wellbores 2902, 2906. Further, these regions 3214 will smoothly close off as 44 heating continues. This beneficial pyrolysis zone 3208B is produced because the two wellbores2902,2906 in each heater well 2900 are properly spaced. In addition, the burners 2905 are at theright depth or location within the first wellbore 2902. In addition, the burners 2905 are at thecorrect intensity based upon the air “A” and fuel “CF* injection rates and compositions.

[0213] It is noted that the same illustration of heat profile generation demonstrated inFigures 32A and 32B where the heater wells 2900 are in end-to-end relation could be made inconnection with heater wells 2900 that are in side-by-side relation. In addition, these conceptscould be combined in a full array of heater wells 2900 that are in both end-to-end and side-to-side relation. This is demonstrated in Figure 33.

[0214] Figure 33 provides a perspective view of a plurality of heater wells 2900 of Figure29A. The wells 2900 make up a large array 2900’ comprised of rows and columns. The array2900’ is provided within a hydrocarbon development area 3300. The hydrocarbon developmentarea 3300 is for the purpose of extracting pyrolyzed hydrocarbon fluids from an organic-rich rockformation 3310.

[0215] In Figure 33, some of the heater wells 2900 are seen in phantom. In some instancesonly wellheads 2910 are shown. However, it is understood that each heater well 2900 will havehardware for injecting a combustible fuel and an oxidant into a first wellbore 2902, a burner(shown at 2905 in Figure 29A) proximate the subsurface formation 3310, and a second wellbore2906. In addition, a horizontal portion 2904 of each of the first wellbores 2902 provides fluidcommunication with respective second wellbores 2906.

[0216] It can be seen from Figure 33 that the heater wells 2900 are aligned both in side-by-side relation and in end-to-end relation. In each instance, the relationship of first wellbores 2902to second wellbores 2906 is alternating. This is indicated by the arrows “I” and “O,” which areseen to be alternating. A spacing between each of the first 2902 and second 2906 wellbores isselected so that following the circulation of heated flue gas through the respective heater wells2900 for a period of time, a first pyrolysis zone from the first wellbore 2902 mates with a secondpyrolysis zone from the second wellbore 2906 in such a manner that (i) a substantiallycontinuous pyrolysis zone of formation hydrocarbons is formed within a substantial portion ofthe organic-rich rock formation 3310 between the first 2902 and second 2906 wellbores. In oneaspect, as a result of circulation, (ii) the combustion products are above a pyrolysis temperaturein each of the respective second wellbores 2906 at or just below the approximate depth of the atleast one combustion burner 2905 in corresponding first wellbores 2902, and fall below a pyrolysis temperature in each of the respective second wellbores 2906 at or just above theapproximate depth of the at least one combustion burner in the corresponding first wellbores2902.

[0217] Returning to Figure 29A, those of ordinary skill in the art will appreciate that theflame generated from hardware such as a downhole combustion burner 2905 generates a flamethat can be extremely hot. As noted above, this creates a point of very high heat which thenquickly diminishes as the flue gas “FG” is circulated through the heater well 2900. To mitigatethis effect, it is proposed in some embodiments to use cowls at or below the burner 2905.

[0218] Figure 34 shows a side view of a burner 3405 disposed at the bottom 3402 of anelongated tubular member 3415. A cowl 3440 is positioned immediately below the burner 3405.The cowl 3440 is preferably fabricated from a heat-resistant material such as ceramic, a temperedsteel, or a refractory metal.

[0219] The cowl 3440 is a tubular body having a wall 3442 and a bore 3445 therein. Thewall 3442 has a plurality of perforations or vents 3446 that provide fluid communication betweenan inner bore 3445 of the cowl 3440 and a surrounding outer region or annulus 3424. In theillustrative cowl 3440 of Figure 34, flanges 3444 extend outwardly from the wall 3442 to createvents 3446. The vents 3446 receive air, indicated at arrow “A,” from the annulus 3424. The air“A,” in turn, mixes with combustible fuel, shown at arrow “CF,” to enable the burner 3405 tocreate a flame. Although not depicted in Figure 34, the arrangement of the air “A” andcombustible fuel “CF* may be reversed such that the vents 3446 receive combustible fuel fromthe surrounding annulus 3424 which mixes with air from the burner 3405 orifice within the innerbore 3445 to enable the burner 3405 to create a flame.

[0220] The use of cowls 3440 helps to contain radiant heat from the burner 3405 and to coolthe hot flue gases “FG” with air “A.” In this respect, the cowls 3440 employ an elongated body3442 which insulates the surrounding casing from immediate contact with the flames. Theelongated body 3442 provides for a more uniform heat distribution from the flames to thesurrounding casing (not shown) and, ultimately, the organic-rich rock formation 300. Because ofthe thermally insulative effect of the cowl 3440, only the cowl 3440 and, perhaps, a relativelyshort length of the surrounding casing need be constructed from a highly temperature-resistantmaterial.

[0221] Additional approaches may be taken to provide for a more uniform heat distributionfrom the flames to the surrounding casing string (such as casing 302 of Fig. 30) and, ultimately, 46 the organic-rich rock formation 300. In one aspect, the relative volume of air “A” injected intothe annulus 3424 may be increased. For example, the air “A” may be injected at about 1.25 to6.0 times the stoichiometric combustion amount.

[0222] In connection with the heater well 2900 and Figures 29A and 32B, various methodsfor in situ heating of a targeted organic-rich rock formation 300 are provided. In these methods,the organic-rich rock formation 300 preferably comprises oil shale. In one embodiment, themethod includes the step of providing a first wellbore 2902 extending to the targeted organic-richrock formation 300. The first wellbore 2902 has a lower end 2901. The method also includesproviding a second wellbore 2906 also having a lower end 2903. The lower end of the secondwellbore 2906 intersects with the lower end 2901 of the first wellbore 2902 through a deviatedportion 2904. In this way, fluid communication between the first 2902 and second 2906wellbores is created.

[0223] The method also includes providing a burner 2905 along the first wellbore 2902. Theburner 2905 is preferably disposed above the lower end 2901 of the first wellbore 2902. Themethod also includes the step of injecting air “A" and a combustible fuel “CF’ into the firstwellbore 2902 and through the burner 2905 so as to combust the combustible fuel “CF.” The air“A” and the combustible fuel “CF” combust at substantially the depth of the organic-rich rockformation 300 to form hot flue gas “FG.” The flue gas “FG” generated from the burner 2905 iscirculated through the deviated portion 2904 and the second wellbore 2906.

[0224] The first wellbore 2902 is preferably completed horizontally, thereby defining a heel2901 and a toe 2903. The second wellbore 2906 is preferably completed substantially vertically.In any arrangement, the combustion products are circulated into and up the second wellbore2906. A heat profile is created from the first wellbore 2902 and second wellbore 2906 thatprovides substantially complete pyrolysis of the organic-rich rock formation between the firstwellbore 2902 and the second wellbore 2906. Preferably, the heat profile defines a pyrolysiszone 2908A that is substantially uniform.

[0225] Igniting the burner 2905 creates a flame. In one aspect, the flame and the circulationof heated air “A” through the heater well 2900 cause the targeted organic-rich rock formation300 to be heated to between about 300° C and 700° C between the heel 2901 and the toe 2903.

[0226] Preferably, the flue gas “FG” or combustion products in the second wellbore 2906 areabove a pyrolysis temperature up to an approximate depth of the hardware 2905 in the firstwellbore 2902. Alternatively, the flue gas “FG" or combustion products in the second wellbore 47 2906 fall below a pyrolysis temperature at or just above the depth of the hardware 2905 in thefirst wellbore 2902.

[0227] In one embodiment, the method further includes heating oil shale in the formation 300in order to pyrolyze at least a portion of the oil shale into hydrocarbon fluids. The hydrocarbonfluids may include gas. The gas is produced and then used as part of the combustible fuel “CF.”In this instance, the method preferably further includes treating the hydrocarbon fluids in order tosubstantially remove H2S from the gas before injecting the gas into the first wellbore 2902. Inone aspect, the combustible fuel “CF&amp;#1523; is a fuel gas. The method may then further includecontrolling the intensity of the burner 2905 by adjusting the composition of the fuel gas “CF.” [0228] As noted, the flue gas “FG” is circulated to the surface. The flue gas “FG” may bevented to the atmosphere. In this instance, the method may further include the step of treatingthe flue gas “FG” to remove NOx components prior to venting the received flue gas “FG” to theatmosphere. Alternatively, if the flue gas “FG” still has significant oxygen content or significantfuel content, the flue gas “FG” may be redirected to be used as an oxidant or fuel supply for.another well or surface combustor.

[0229] In certain embodiments, excess air “A” is injected to cool the flame, reduce NO*, andimprove transfer of heat away from the burner 2905. In other embodiments, excess fuel “CF’ isinjected. Use of excess fuel can reduce compression costs since typically fuel is available atpressure whereas air “A" is only available at atmospheric conditions. However, when usingexcess fuel “CF” it is generally desirable to insure that no uncombusted fuel is vented to theenvironment with the combustion products.

[0230] When excess air “A” is used, the flue gas “FG” may be collected and, optionally,compressed. The flue gas “FG” containing oxygen, preferably >10 mol%, may be mixed withcompressed air “A.” The mixture may then be delivered back into the first wellbore 2902 (orinto another input “I" wellbore) as air “A.” Recapturing the flue gas “FG” allows the step ofinjecting the air “A" to use the pressure from the flue gas “FG," thereby reducing compressionneeds at the heater well 2900. In certain cases, the flue gas “FG” may be useable without mixingwith compressed air. % [0231] In another aspect, the collected flue gas “FG” is compressed. The flue gas “FG"containing combustible gases, preferably >25 mol%, may then be mixed with compressed fuel.The mixture may then be delivered back into the tubular member 2902 together as combustiblefuel “CF.” The combustible fuel “CF” is preferably injected into the first wellbore 2902 under 48 pressure. In one aspect, the combustible fuel “CF” is injected under a pressure of greater thanabout 200 psia. In another aspect, the combustible fuel “CF” is injected under a pressure ofgreater than about 600 psia. In still another aspect, the combustible fuel “CF’ is injected under apressure of only about to 200 psia. In certain cases, the flue gas may be useable without mixingwith compressed fuel.

[0232] When excess fuel “CF’ is used, the collected flue gas “FG” may alternatively bedirected to another well as a fuel stream. In such a case, the flue gas “FG” still has combustiblecomponents in it. The flue gas “FG” may be first treated to remove free water prior to reuse.The flue gas “FG” may also be recompressed. Alternatively, the flue gas “FG” may be used atthe surface to fire turbines or to generate steam. If the fuel components in the flue gas “FG” arein low concentration, catalytic burners may be used to improve combustion performance of theselow BTU mixtures.

[0233] . When excess fuel “CF’ is used, it may be desirable to switch the air “A” and fuel“CF’ flow. This means that air “A” will flow through the inner tubular 305 and fuel through theannulus 308. A flame generated by this method is a so-called “reverse diffusion” flame and canlead to lower NOx generation in certain cases.

[0234] In another aspect, the flue gas “FG” is again collected from the heater well 2900 atthe surface. The method may then include the step of monitoring the collected flue gas “FG” forthe presence of combustible species to assess whether the burner 2905 is firing properly. Thecombustible species may comprise at least one of methane, ethane, hydrogen (H2), and carbonmonoxide.

[0235] In one embodiment, the method further comprises reversing the inlet and outletfunctions of the two wellbores 2902 and 2906 after the targeted organic-rich rock formation 300has been heated for a period of time. For example, heating may take place for a period of timesufficient to begin pyrolyzing kerogen existing in the formation adjacent the first wellbore 2902both above the heel 2901 and towards the toe 2903. Thereafter, air “A” and the combustible fuel“CF” are injected into the second wellbore 2906 and through a burner in the second wellbore2906 so as to combust the combustible fuel “CF” and to further heat the targeted organic-richrock formation 300 adjacent the second wellbore 2906 and towards the heel 2901 of the firstwellbore 2902. Flue gas “FG” generated from the burner 2905 is circulated through the firstwellbore 2902 and to the surface. The burner (not shown) in the second wellbore 2906 may be 49 placed during initial instillation of the well or when the reversal occurs. The burner 2905 in thefirst wellbore 2902 may be left in place or removed when the reversal occurs.

[0236] Different sizes of burners 2905 may be employed in the heater well 2900. The sizewill depend on the length of the portion of the formation to be heated. For example, the burner2905 may supply about 0.5 to 3 kW of thermal energy per meter of formation to be heated, ormore preferably 1.0 to 2.5 kW/m of thermal energy.

[0237] It is desirable to control the heat conducted into the formation 300. Thus, in oneembodiment the position of the burner 2905, the rate of injecting the combustible fuel “CF,” therate of injecting the air “A,” or combinations thereof, are controlled so that the temperature of theflue gas “FG” traveling into the second wellbore 2906 is about 300° C to 700° C across amajority of the organic-rich rock formation 300. The rate of injecting the combustible fuel “CF’may be reduced over time.

[0238] In one embodiment, the combustible fuel “CF’ is a fuel gas such as natural gas. Theintensity of the burner 2905 is then controlled by adjusting the composition of the fuel gas. Forinstance, natural gas may be used as the fuel gas and diluted with added inert components. Theadded inert components may comprise at least one of carbon dioxide (C02) or nitrogen (N2).Reducing flame intensity can lead to reduced NO* generation.

[0239] Another method for heating a subsurface formation is provided which uses a plurality2900’ of heater wells 2900. In this embodiment, the first wellbore 2902, the second wellbore2906, and the burner 2905 define a first heater well 2900. A plurality 2900’ of additional heaterwells 2900 is then provided, each of which also comprises a first wellbore 2902, a secondwellbore 2906, and a burner 2905 within the first wellbore 2902. The method further includesarranging the first heater well 2900 and the plurality 2900’ of additional heater wells 2900 suchthat the respective first wellbores 2902 and the respective second wellbores 2906 are inalternating relation. Air “A” and a combustible fuel “CF’ are injected into the first wellbore2902 and through the burner 2905 of each of the respective plurality 2900’ of additional heaterwells 2900 so as to combust the combustible fuel “CF’ within the plurality 2900’ of additionalheater wells 2900. Flue gas “FG” generated from each of the burners 2905 is circulated throughthe respective second wellbores 2906 of the plurality 2900’ of additional heater wells 2900 and tothe surface.

[0240] Certain features of the present inventions relate to improving the performance ofdownhole burners for heating organic-rich rock formations by extending the region of heating 50 and providing for more uniform heating. In addition, certain features of the present inventionsrelate to reducing or mitigating maximum temperatures. Reducing maximum temperaturesreduces the needs for using costly temperature-resistant materials in the well construction.Reducing maximum temperatures also avoids certain problems posed by high temperatures in aheater well. For example, the presence of very high temperatures can lead to inefficient heatingof the subsurface, causing certain areas to become much hotter than required for pyrolysis tooccur, or causing pyrolysis to take place at an undesirably high rate in certain regions of aformation. Reducing the temperature also allows NO* emissions to be reduced. By circulatingheated flue gas through adjacent wellbores and conducting thermal energy from each wellboreinto the selected organic-rich rock formation, a more uniform heating is achieved over asubsurface region.

[0241] Wobbe Index (WI) is often used as a key measure of fuel quality. WI is equal to theratio of the lower heating value to the square root of the gas specific gravity. Fuel quality controlmay be useful for shale oil developments where the produced gas composition may change overthe life of the field and where the gas typically has significant amounts of C02, CO, and H2 inaddition to light hydrocarbons. Commercial scale oil shale retorting is expected to produce a gascomposition that changes with time.

[0242] Achieving a certain hydrogen content for low-BTU fuels may be desirable to achieveappropriate bum properties. In certain embodiments of the processes herein, the H2 content ofthe fuel gas is adjusted via separation or addition in the surface facilities to optimize burnerperformance. Adjustment of H2 content in non-shale oil surface facilities, utilizing low BTUfuels has been discussed in the patent literature (e.g., U.S. Pat. No. 6,684,644 and U.S. Pat. No.6,858,049, the entire disclosures of which are hereby incorporated by reference).

[0243] The process of heating formation hydrocarbons within an organic-rich rock formation,for example, by pyrolysis, may generate fluids. The heat-generated fluids may include waterwhich is vaporized within the formation. In addition, the action of heating kerogen producespyrolysis fluids which tend to expand upon heating. The produced pyrolysis fluids may includenot only water, but also, for example, hydrocarbons, oxides of carbon, ammonia, molecularnitrogen, and molecular hydrogen. Therefore, as temperatures within a heated portion of theformation increase, a pressure within the heated portion may also increase as a result of increasedfluid generation, molecular expansion, and vaporization of water. Thus, some corollary existsbetween subsurface pressure in an oil shale formation and the fluid pressure generated during 51 pyrolysis. This, in turn, indicates that formation pressure may be monitored to detect theprogress of a kerogen conversion process.

[0244] The pressure within a heated portion of an organic-rich rock formation depends onother reservoir characteristics. These may include, for example, formation depth, distance from a 5 heater well, a richness of the formation hydrocarbons within the organic-rich rock formation, thedegree of heating, and/or a distance from a producer well.

[0245] It may be desirable for the developer of an oil shale field to monitor formationpressure during development. Pressure within a formation may be determined at a number ofdifferent locations. Such locations may include, but may not be limited to, at a wellhead and at 10 varying depths within a wellbore. In some embodiments, pressure may be measured at aproducer well. In an alternate embodiment, pressure may be measured at a heater well. In stillanother embodiment, pressure may be measured downhole of a dedicated monitoring well.

[0246] The process of heating an organic-rich rock formation to a pyrolysis temperaturerange not only will increase formation pressure, but will also increase formation permeability. 15 The pyrolysis temperature range should be reached before substantial permeability has beengenerated within the organic-rich rock formation. An initial lack of permeability may prevent thetransport of generated fluids from a pyrolysis zone within the formation. In this manner, as heatis initially transferred from a heater well to an organic-rich rock formation, a fluid pressurewithin the organic-rich rock formation may increase proximate to that heater well. Such an20 increase in fluid pressure may be caused by, for example, the generation of fluids duringpyrolysis of at least some formation hydrocarbons in the formation.

[0247] Alternatively, pressure generated by expansion of pyrolysis fluids or other fluidsgenerated in the formation may be allowed to increase. This assumes that an open path to aproduction well or other pressure sink does not yet exist in the formation. In one aspect, a fluid 25 pressure may be allowed to increase to or above a lithostatic stress. In this instance, fractures inthe hydrocarbon containing formation may form when the fluid pressure equals or exceeds thelithostatic stress. For example, fractures may form from a heater well to a production well. Thegeneration of fractures within the heated portion may reduce pressure within the portion due tothe production of produced fluids through a production well. 30 [0248] Once pyrolysis has begun within an organic-rich rock formation, fluid pressure may vary depending upon various factors. These include, for example, thermal expansion ofhydrocarbons, generation of pyrolysis fluids, rate of conversion, and withdrawal of generated 1 52 fluids from the formation. For example, as fluids are generated within the formation, fluidpressure within the pores may increase. Removal of generated fluids from the formation maythen decrease the fluid pressure within the near wellbore region of the formation.

[0249] In certain embodiments, a mass of at least a portion of an organic-rich rock formationmay be reduced due, for example, to pyrolysis of formation hydrocarbons and the production ofhydrocarbon fluids from the formation. As such, the permeability and porosity of at least aportion of the formation may increase. Any in situ method that effectively produces oil and gasfrom oil shale will create permeability in what was originally a very low permeability rock. Theextent to which this will occur is illustrated by the large amount of expansion that must beaccommodated if fluids generated from kerogen are unable to flow. The concept is illustrated inFigure 5.

[0250] Figure 5 provides a bar chart comparing one ton of Green River oil shale before 50and after 51 a simulated in situ, retorting process. The simulated process was carried out at 2,400psi and 750° F on oil shale having a total organic carbon content of 22 wt. % and a Fisher assayof 42 gallons/ton. Before the conversion, a total of 15.3 ft3 of rock matrix .52 existed. Thismatrix comprised 7.2 ft3 of mineral 53, i.e., dolomite, limestone, etc., and 8.1 ft3 of kerogen 54imbedded within the shale. As a result of the conversion the material expanded to 26.1 ft3 55.This represented 7.2 ft3 of mineral 56 (the same number as before the conversion), 6.6 ft3 ofhydrocarbon liquid 57,9.4 ft3 of hydrocarbon vapor 58, and 2.9 ft3 of coke 59. It can be seen thatsubstantial volume expansion occurred during the conversion process. This, in turn, increasespermeability of the rock structure.

[0251] In an embodiment, heating a portion of an organic-rich rock formation in situ to apyrolysis temperature may increase permeability of the heated portion. For example,permeability may increase due to formation of thermal fractures within the heated portion causedby application of heat. As the temperature of the heated portion increases, water may beremoved due to vaporization. The vaporized water may escape and/or be removed from theformation. In addition, permeability of the heated portion may also increase as a result ofproduction of hydrocarbon fluids from pyrolysis of at least some of the formation hydrocarbonswithin the heated portion on a macroscopic scale.

[0252] Certain systems and methods described herein may be used to treat formationhydrocarbons in at least a portion of a relatively low permeability formation (e.g., in "tight"formations that contain formation hydrocarbons). Such formation hydrocarbons may be heated 53 to pyrolyze at least some of the formation hydrocarbons in a selected zone of the formation.Heating may also increase the permeability of at least a portion of the selected zone.Hydrocarbon fluids generated from pyrolysis may be produced from the formation, therebyfurther increasing the formation permeability.

[0253] Permeability of a selected zone within the heated portion of the organic-rich rockformation may also rapidly increase while the selected zone is heated by conduction. Forexample, permeability of an impermeable organic-rich rock formation may be less than about 0.1millidarcy before heating. In some embodiments, pyrolyzing at least a portion of organic-richrock formation may increase permeability within a selected zone of the portion to greater thanabout 10 millidarcies, 100 millidarcies, 1 Darcy, 10 Darcies, 20 Darcies, or SO Darcies.Therefore, a permeability of a selected zone of the portion may increase by a factor of more thanabout 10, 100, 1,000, 10,000, or 100,000. In one embodiment, the organic-rich rock formationhas an initial total permeability less than 1 millidarcy, alternatively less than 0.1 or 0.01millidarcies, before heating the organic-rich rock formation. In one embodiment,- the organic-rich rock formation has a post heating total permeability of greater than 1 millidarcy,alternatively, greater than 10, SO or 100 millidarcies, after heating the organic-rich rock

I formation.

[0254] In connection with heating the organic-rich rock formation, the organic-rich rockformation may optionally be fractured to aid heat transfer or hydrocarbon fluid production. Inone instance, fracturing may be accomplished naturally by creating thermal fractures within theformation through application of heat. Thermal fracture formation is caused by thermalexpansion of the rock and fluids and by chemical expansion of kerogen transforming into oil andgas. Thermal fracturing can occur both in the immediate region undergoing heating, and incooler neighboring regions. The thermal fracturing in the neighboring regions is due topropagation of fractures and tension stresses developed due to the expansion in the hotter zones.Thus, by both heating the organic-rich rock and transforming the kerogen to oil and gas, thepermeability is increased not only from fluid formation and vaporization, but also via thermalfracture formation. The increased permeability aids fluid flow within the formation andproduction of the hydrocarbon fluids generated from the kerogen.

[0255] In addition, a process known as hydraulic fracturing may be used. Hydraulicfracturing is a process known in the art of oil and gas recovery where a fracture fluid ispressurized within the wellbore above the fracture pressure of the formation, thus developingfracture planes within the formation to relieve the pressure generated within the wellbore.

Hydraulic fractures may be used to create additional permeability and/or be used to provide anextended geometry for a heater well. The WO 2005/010320 patent publication incorporatedabove describes one such method.

[0256] In connection with the production of hydrocarbons from a rock matrix, particularlythose of shallow depth, a concern may exist with respect to earth subsidence. This is particularlytrue in the in situ heating of organic-rich rock where a portion of the matrix itself is thermallyconverted and removed. Initially, the formation may contain formation hydrocarbons in solidform, such as, for example, kerogen. The formation may also initially contain water-solubleminerals. Initially, the formation may also be substantially impermeable to fluid flow.

[0257] The in situ heating of the matrix pyrolyzes at least a portion of the formationhydrocarbons to create hydrocarbon fluids. This, in tum, creates permeability within a matured(pyrolyzed) organic-rich rock zone in the organic-rich rock formation. The combination ofpyrolyzation and increased permeability permits hydrocarbon fluids to be produced from theformation. At the same time, the loss of supporting matrix material also creates the potential forsubsidence relative to the earth surface.

[0258] In some instances, subsidence is sought to be minimized in order to avoidenvironmental or hydrogeological impact. In this respect, changing the contour and relief of theearth surface, even by a few inches, can change runoff patterns, affect vegetation patterns, andimpact watersheds. In addition, subsidence has the potential of damaging production or heaterwells formed in a production area. Such subsidence can create damaging hoop andcompressional stresses on wellbore casings, cement jobs, and equipment downhole.

[0259] In order to avoid or minimize subsidence, it is proposed to leave selected portions ofthe formation hydrocarbons substantially unpyrolyzed. This serves to preserve one or moreunmatured, organic-rich rock zones. In some embodiments, the unmatured organic-rich rockzones may be shaped as substantially vertical pillars extending through a substantial portion ofthe thickness of the organic-rich rock formation.

[0260] The heating rate and distribution of heat within the formation may be designed andimplemented to leave sufficient unmatured pillars to prevent subsidence. In one aspect, heatinjection wellbores are formed in a pattern such that untreated pillars of oil shale are lefttherebetween to support the overburden and prevent subsidence. 55 [0261] It is preferred that thermal recovery of oil and gas be conducted before any solutionmining of nahcolite or other water-soluble minerals present in the formation. Solution miningcan generate large voids in a rock formation and collapse breccias in an oil shale developmentarea. These voids and brecciated zones may pose problems for in situ and mining recovery of oilshale, further increasing the utility of supporting pillars.

[0262] In some embodiments, compositions and properties of the hydrocarbon fluidsproduced by an in situ, conversion process may vary depending on, for example, conditionswithin an organic-rich rock formation. Controlling heat and/or heating rates of a selected sectionin an organic-rich rock formation may increase or decrease production of selected producedfluids.

[0263] In some embodiments, a heater well may be turned down and/or off after an averagetemperature in a formation may have reached a selected temperature. Turning down and/or offthe heater well may reduce input energy costs, substantially inhibit overheating of the formation,and allow heat to substantially transfer into colder regions of the formation.

[0264] Temperature (and average temperatures) within a heated organic-rich rock formationmay vary, depending on, for example, proximity to a heater well, thermal conductivity andthermal diffusivity of the formation, type of reaction occurring, type of formation hydrocarbon,and the presence of water within the organic-rich rock formation. At points in the field wheremonitoring wells are established, temperature measurements may be taken directly in thewellbore. Further, at heater wells the temperature of the immediately surrounding formation isfairly well understood. However, it is desirable to interpolate temperatures to points in theformation intermediate temperature sensors and heater wells.

[0265] In accordance with one aspect of the production processes of the present inventions, atemperature distribution within the organic-rich rock formation may be computed using anumerical simulation model. The numerical simulation model may calculate a subsurfacetemperature distribution through interpolation of known data points and assumptions offormation conductivity. In addition, the numerical simulation model may be used to determineother properties of the formation under the assessed temperature distribution. For example, thevarious properties of the formation may include, but are not limited to, permeability of theformation. In a simpler context, temperature sensors may be placed along the wellbores 2902,2904,2906. 56 [0266] The numerical simulation model may also include assessing various properties of afluid formed within an organic-rich rock formation under the assessed temperature distribution.For example, the various properties of a formed fluid may include, but are not limited to, acumulative volume of a fluid formed in the formation, fluid viscosity, fluid density, and acomposition of the fluid formed in the formation. Such a simulation may be used to assess theperformance of a commercial-scale operation or small-scale field experiment. For example, aperformance of a commercial-scale development may be assessed based on, but not limited to, atotal volume of product that may be produced from a research-scale operation.

[0267] Some embodiments include producing at least a portion of the hydrocarbon fluidsfrom the organic-rich rock formation. The hydrocarbon fluids may be produced throughproduction wells. Production wells may be cased or uncased wells and drilled and completedthrough methods known in the art.

[0266] Some embodiments further include producing a production fluid from the organic-richrock formation where the production fluid contains the hydrocarbon fluids and an aqueous fluid.The aqueous fluid may contain water-soluble minerals and/or migratory contaminant species. Insuch case, the production fluid may be separated into a hydrocarbon stream and an aqueousstream at a surface facility. Thereafter the water-soluble minerals and/or migratory contaminantspecies may be recovered from the aqueous stream. This embodiment may be combined withany of the other aspects of the invention discussed herein.

[0269] The produced hydrocarbon fluids may include a pyrolysis oil component (orcondensable component) and a pyrolysis gas component (or non-condensable component).Condensable hydrocarbons produced from the formation will typically include paraffins,cycloalkanes, mono-aromatics, and di-aromatics as components. Such condensablehydrocarbons may also include other components such as tri-aromatics and other hydrocarbonspecies.

[0270] In certain embodiments, a majority of the hydrocarbons in the produced fluid mayhave a carbon number of less than approximately 25. Alternatively, less than about 15 weight %of the hydrocarbons in the fluid may have a carbon number greater than approximately 25. Thenon-condensable hydrocarbons may include, but are not limited to, hydrocarbons having carbonnumbers less than 5.

[0271] In certain embodiments, the API gravity of the condensable hydrocarbons in theproduced fluid may be approximately 20 or above (e.g., 25, 30, 40, 50, etc.). In certain 57 embodiments, the hydrogen to carbon atomic ratio in produced fluid may be at leastapproximately 1.7 (e.g., 1.8,1.9, etc.).

[0272] One embodiment of the invention includes an in situ method of producinghydrocarbon fluids with improved properties from an organic-rich rock formation. Applicantshave surprisingly discovered that the quality of the hydrocarbon fluids produced from in situheating and pyrolysis of an organic-rich rock formation may be improved by selecting sections ofthe organic-rich rock formation with higher lithostatic stress for in situ heating and pyrolysis.

[0273] The method may include in situ heating of a section of the organic-rich rockformation that has a high lithostatic stress to form hydrocarbon fluids with improved properties.The method may include creating the hydrocarbon fluid by pyrolysis of a solid hydrocarbonand/or a heavy hydrocarbon present in the organic-rich rock formation. Embodiments mayinclude the hydrocarbon fluid being partially, predominantly or substantially completely createdby pyrolysis of the solid hydrocarbon and/or heavy hydrocarbon present in the organic-rich rockformation. The method may include heating the section of the organic-rich rock formation byany method, including any of the methods described herein. For example, the method mayinclude heating the section of the organic-rich rock formation by electrical resistance heating.Further, the method may include heating the section of the organic-rich rock formation throughuse of a heated heat transfer fluid. The method may include heating the section of the organic-rich rock formation to above 270° C. Alternatively, the method may include heating the sectionof the organic-rich rock formation between 270° C and 500° C.

[0274] The method may include heating in situ a section of the organic-rich rock formationhaving a lithostatic stress greater than 200 psi and producing a hydrocarbon fluid from the heatedsection of the organic-rich rock formation. In alternative embodiments, the heated section of theorganic-rich rock formation may have a lithostatic stress greater than 400 psi. In alternativeembodiments, the heated section of the organic-rich rock formation may have a lithostatic stressgreater than 800 psi, greater than 1,000 psi, greater than 1,200 psi, greater than 1,500 psi orgreater than 2,000 psi. Applicants have found that in situ heating and pyrolysis of organic-richrock formations with increasing amounts of stress lead to the production of hydrocarbon fluidswith improved properties.

[0275] The lithostatic stress of a section of an organic-rich formation can normally beestimated by recognizing that it will generally be equal to the weight of the rocks overlying theformation. The density of the overlying rocks can be expressed in units of psi/ft. Generally, this 58 value will fall between 0.8 and 1.1 psi/ft and can often be approximated as 0.9 psi/ft. As a resultthe lithostatic stress of a section of an organic-rich formation can be estimated by multiplying thedepth of the organic-rich rock formation interval by 0.9 psi/ft. Thus the lithostatic stress of asection of an organic-rich formation occurring at about 1,000 ft can be estimated to be about (0.95 psi/ft) multiplied by (1,000 ft) or about 900 psi. If a more precise estimate of lithostatic stress isdesired the density of overlying rocks can be measured using wireline logging techniques or bymaking laboratory measurements on samples recovered from coreholes. The method mayinclude heating a section of the organic-rich rock formation that is located at a depth greater than200 ft below the earth's surface. Alternatively, the method may include heating a section of the10 . organic-rich rock formation that is located at a depth greater than 500 ft below the earth's surface, greater than 1,000 ft below the earth's surface, greater than 1,200 ft below the earth's surface,greater than 1,500 ft below the earth's surface, or greater than 2,000 ft below the earth’s surface.

[0276] The organic-rich rock formation may be, for example, a heavy hydrocarbon formationor a solid hydrocarbon formation. Particular examples of such formations may include an oil 15 shale formation, a tar sands formation or a coal formation. Particular formation hydrocarbonspresent in such formations may include oil shale, kerogen, coal, and/or bitumen.

[0277] The hydrocarbon fluid produced from the organic-rich rock formation may includeboth a condensable hydrocarbon portion (e.g. liquid) and a non-condensable hydrocarbon portion(e.g. gas). The hydrocarbon fluid may additionally be produced together with non-hydrocarbon 20 fluids. Exemplary non-hydrocarbon fluids include, for example, water, carbon dioxide, hydrogensulfide, hydrogen, ammonia, and/or carbon monoxide.

[0278] . The condensable hydrocarbon portion of the hydrocarbon fluid may be a fluid presentwithin different locations associated with an organic-rich rock development project. Forexample, the condensable hydrocarbon portion of the hydrocarbon fluid may be a fluid present 25 within a production well that is in fluid communication with the organic-rich rock formation.The production well may serve as a device for withdrawing the produced hydrocarbon fluidsfrom the organic-rich rock formation. Alternatively, the condensable hydrocarbon portion maybe a fluid present within processing equipment adapted to process hydrocarbon fluids producedfrom the organic-rich rock formation. Exemplary processing equipment is described herein.30 Alternatively, the condensable hydrocarbon portion may be a fluid present within a fluid storagevessel. Fluid storage vessels may include, for example, fluid storage tanks with fixed or floatingroofs, knock-out vessels, and other intermediate, temporary or product storage vessels.Alternatively, the condensable hydrocarbon portion may be a fluid present within a fluid WO 2008/143745 transportation pipeline. A fluid transportation pipeline may include, for example, piping fromproduction wells to processing equipment or fluid storage vessels, piping from processingequipment to fluid storage vessels, or pipelines associated with collection or transportation offluids to or from intermediate or centralized storage locations.

[0279} The following discussion of Figures 7-16 concerns data obtained in Examples 1 - 5which are discussed below in the section labeled "Experiments". The data was obtained throughexperimental procedures, gas and liquid sample collection procedures, hydrocarbon gas samplegas chromatography (GC) analysis methodology, gas sample GC peak integration methodology,gas sample GC peak identification methodology, whole oil gas chromatography (WOGC)analysis methodology, whole oil gas chromatography (WOGC) peak integration methodology,whole oil gas chromatography (WOGC) peak identification methodology, and pseudo componentanalysis methodology discussed in the Experiments section. For clarity, when referring to gaschromatography chromatograms of hydrocarbon gas samples, graphical data is provided for oneunstressed experiment through Example 1, two 400 psi stressed experiments through Examples 2and 3, and two 1,000 psi stressed experiments through Examples 4 and 5. When referring towhole oil gas chromatography (WOGC) chromatograms of liquid hydrocarbon samples,graphical data is provided for one unstressed experiment through Example 1, one 400 psi stressedexperiments through Example 3, and one 1,000 psi stressed experiment through Example 4.

[0280] Figure 7 is a graph of the weight percent of each carbon number pseudo componentoccurring from G6 to C38 for each of the three stress levels tested and analyzed in the laboratoryexperiments discussed herein. The pseudo component weight percentages were obtained throughthe experimental procedures, liquid sample collection procedures, whole oil gas chromatography(WOGC) analysis methodology, whole oil gas chromatography (WOGC) peak identification andintegration methodology, and pseudo component analysis methodology discussed in theExperiments section. For clarity, the pseudo component weight percentages are taken as apercentage of the entire C3 to pseudo C38 whole oil gas chromatography areas and calculatedweights. Thus the graphed C6 to C38 weight percentages do not include the weight contributionof the associated gas phase product from any of the experiments which was separately treated.Further, the graphed weight percentages do not include the weight contribution of any liquidhydrocarbon compounds heavier than (i.e. having a longer retention time than) the C38 pseudocomponent. The y-axis 2000 represents the concentration in terms of weight percent of each C6to C38 pseudo component in the liquid phase. The x-axis 2001 contains the identity of eachhydrocarbon pseudo component from C6 to C38. The data points occurring on line 2002 WO 2008/143745 PCMJS2008/005008 60 represent the weight percent of each C6 to C38 pseudo component for the unstressed experimentof Example 1. The data points occurring on line 2003 represent the weight percent of each C6 toC38 pseudo component for the 400 psi stressed experiment of Example 3. While the data pointsoccurring on line 2004 represent the weight percent of each C6 to C38 pseudo component for the5 1,000 psi stressed experiment of Example 4. From Figure 7 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 2002, contains alower weight percentage of lighter hydrocarbon components in the C8 to C17 pseudo componentrange and a greater weight percentage of heavier hydrocarbon components in the C20 to C29pseudo component range, both as compared to the 400 psi stress experiment hydrocarbon liquid10 and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data pointsoccurring on line 2003, it is apparent that the intermediate level 400 psi stress experimentproduced a hydrocarbon liquid having C8 to C17 pseudo component concentrations between theunstressed experiment represented by line 2002 and the 1,000 psi stressed experimentrepresented by line 2004. It is noted that the C17 pseudo component data for both the 400 psi13 and 1,000 psi stressed experiments are about equal. Further, it is apparent that the weightpercentage of heavier hydrocarbon components in the C20 to C29 pseudo component range forthe intermediate stress jevel experiment represented by line 2003 falls between the unstressedexperiment (Line 2002) hydrocarbon liquid and the 1,000 psi stress experiment (Line 2004)hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced20 a hydrocarbon liquid having C8 to C17 pseudo component concentrations greater than both theunstressed experiment represented by line 2002 and the 400 psi stressed experiment represented. by line 2003. Further, it is apparent that the weight percentage of heavier hydrocarboncomponents in the C20 to C29 pseudo component range for the high level stress experimentrepresented by line 2004 are less than both the unstressed experiment (Line 2002) hydrocarbon25 liquid and the 400 psi stress experiment (Line 2003) hydrocarbon liquid. Thus pyrolyzing oilshale under increasing levels of lithostatic stress appears to produce hydrocarbon liquids havingincreasingly lighter carbon number distributions.

[0281] Figure 8 is a graph of the weight percent ratios of each carbon number pseudocomponent occurring from C6 to C38 as compared to the C20 pseudo component for each of the30 three stress levels tested and analyzed in the laboratory experiments discussed herein. Thepseudo component weight percentages were obtained as described for Figure 7. The y-axis 2020represents the weight ratio of each C6 to C38 pseudo component compared to the C20 pseudocomponent in the liquid phase. The x-axis 2021 contains the identity of each hydrocarbonpseudo component ratio from C6/C20 to C38/C20. The data points occurring on line 2022 61 represent the weight ratio of each C6 to C38 pseudo component to C20 pseudo component for theunstressed experiment of Example 1. The data points occurring on line 2023 represent theweight ratio of each C6 to C38 pseudo component to C20 pseudo component for the 400 psistressed experiment of Example 3. While the data points occurring on line 2024 represent theweight ratio of each C6 to C38 pseudo component to C20 pseudo component for the 1,000 psistressed experiment of Example 4. From Figure 8 it can be seen that the hydrocarbon liquidproduced in the unstressed experiment, represented by data points on line 2022, contains a lowerweight percentage of lighter hydrocarbon components in the C8 to C18 pseudo component rangeas compared to the C20 pseudo component and a greater weight percentage of heavierhydrocarbon components in the C22 to C29 pseudo component range as compared to the C20pseudo component, both as compared to the 400 psi stress experiment hydrocarbon liquid and the1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line2023, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbonliquid having C8 to C18 pseudo component concentrations as compared to the C20 pseudocomponent between the unstressed experiment represented by line 2022 and the 1,000 psistressed experiment represented by line 2024. Further, it is apparent that the weight percentageof&amp;#1523; heavier hydrocarbon components in the C22 to C29 pseudo component range as compared tothe C20 pseudo component for the intermediate stress level experiment represented by line 2023falls between the unstressed experiment (Line 2022) hydrocarbon liquid and the 1,000 psi stressexperiment (Line 2024) hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psistress experiment produced a hydrocarbon liquid having C8 to Cl 8 pseudo componentconcentrations as compared to the C20 pseudo component greater than both the unstressedexperiment represented by line 2022 and the 400 psi stressed experiment represented by line2023. Further, it is apparent that the weight percentage of heavier hydrocarbon components inthe C22 to C29 pseudo component range as compared to the C20 pseudo component for the highlevel stress experiment represented by line 2024 are less than both the unstressed experiment(Line 2022) hydrocarbon liquid and the 400 psi stress experiment (Line 2023) hydrocarbonliquid. This analysis further supports the relationship that pyrolyzing oil shale under increasinglevels of lithostatic stress produces hydrocarbon liquids having increasingly lighter carbonnumber distributions.

[0282] Figure 9 is a graph of the weight percent ratios of each carbon number pseudocomponent occurring from C6 to C38 as compared to the C25 pseudo component for each of thethree stress levels tested and analyzed in the laboratory experiments discussed herein. Thepseudo component weight percentages were obtained as described for Figure 7. The y-axis 2040 WO 2008/143745 represents the weight ratio of each C6 to C38 pseudo component compared to the C25 pseudocomponent in the liquid phase. The x-axis 2041 contains the identity of each hydrocarbonpseudo component ratio from C6/C25 to C38/C25. The data points occurring on line 2042represent the weight ratio of each C6 to C38 pseudo component to C25 pseudo component for theunstressed experiment of Example 1. The data points occurring on line 2043 represent theweight ratio of each C6 to C38 pseudo component to C25 pseudo component for the 400 psistressed experiment of Example 3. While the data points occurring on line 2044 represent theweight ratio of each C6 to C38 pseudo component to C25 pseudo component for the 1,000 psistressed experiment of Example 4. From Figure 9 it can be seen that the hydrocarbon liquidproduced in the unstressed experiment, represented by data points on line 2042, contains a lowerweight percentage of lighter hydrocarbon components in the C7 to C24 pseudo component range.as compared to. the C25 pseudo component and a greater weight percentage of heavierhydrocarbon components in the C26 to C29 pseudo component range as compared to the C25pseudo component, both as compared to the 400 psi stress experiment hydrocarbon liquid and the1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line2043, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbonliquid having C7 to C24 pseudo component concentrations as compared to the C25 pseudocomponent between the unstressed experiment represented by line 2042 and the 1,000 psistressed experiment represented by line 2044. Further, it is apparent that the weight percentageof heavier hydrocarbon components in the C26 to C29 pseudo component range as compared tothe C25 pseudo component for the intermediate stress level experiment represented by line 2043falls between the unstressed experiment (Line 2042) hydrocarbon liquid and the 1,000 psi stressexperiment (Line 2044) hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psistress experiment produced a hydrocarbon liquid having C7 to C24 pseudo componentconcentrations as compared to the C25 pseudo component greater than both the unstressedexperiment represented by line 2042 and the 400 psi stressed experiment represented by line2043. Further, it is apparent that the weight percentage of heavier hydrocarbon components inthe C26 to C29 pseudo component range as compared to the C25 pseudo component for the highlevel stress experiment represented by line 2044 are less than both the unstressed experiment(Line 2042) hydrocarbon liquid and the 400 psi stress experiment (Line 2043) hydrocarbonliquid. This analysis further supports the relationship that pyrolyzing oil shale under increasinglevels of lithostatic stress produces hydrocarbon liquids having increasingly lighter carbonnumber distributions. 63 [0283] Figure 10 is a graph of the weight percent ratios of each carbon number pseudocomponent occurring from C6 to C38 as compared to the C29 pseudo component for each of thethree stress levels tested and analyzed in the laboratory experiments discussed herein. Thepseudo component weight percentages were obtained as described for Figure 7. The y-axis 2060represents the weight ratio of each C6 to C38 pseudo component compared to the C29 pseudocomponent in the liquid phase. The x-axis 2061 contains the identity of each hydrocarbonpseudo component ratio from C6/ C29 to C38/ C29. The data points occurring on line 2062represent the weight ratio of each C6 to C38 pseudo component to C29 pseudo component for theunstressed experiment of Example 1. The data points occurring on line 2063 represent theweight ratio of each G6 to C38 pseudo component to C29 pseudo component for the 400 psistressed experiment of: Example 3. While the data points occurring on line 2064 represent theweight ratio of each C6 to C38 pseudo component to C29 pseudo component for the 1,000 psistressed experiment of Example 4. From Figure 10 it can be seen that the hydrocarbon liquidproduced in the unstressed experiment, represented by data points on line 2062, contains a lowerweight percentage of lighter hydrocarbon components in the C6 to C28 pseudo component rangeas compared to the C29 pseudo component, both as compared to the 400 psi stress experimenthydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at thedata points occurring on line 2063, it is apparent that the intermediate level 400 psi stressexperiment produced a hydrocarbon liquid having C6 to C28 pseudo component concentrationsas compared to the C29 pseudo component between the unstressed experiment represented byline 2062 and the 1,000 psi .stressed experiment represented by line 2064. Lastly, it is apparentthat the high level 1,000 psi stress experiment produced a hydrocarbon liquid having C6 to C28pseudo component concentrations as compared to the C29 pseudo component greater than boththe unstressed experiment represented by line 2062 and the 400 psi stressed experimentrepresented by line 2063. This analysis further supports the relationship that pyrolyzing oil shaleunder increasing levels of lithostatic stress produces hydrocarbon liquids having increasinglylighter carbon number distributions.

[0284] Figure 11 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from the normal&amp;#1470;C6 alkane to the normal-C38 alkane for each of the three stress levelstested and analyzed in the laboratory experiments discussed herein. The normal alkanecompound weight percentages were obtained as described for Figure 7, except that eachindividual normal alkane compound peak area integration was used to determine each respectivenormal alkane compound weight percentage. For clarity, the normal alkane hydrocarbon weightpercentages are taken as a percentage of the entire C3 to pseudo C38 whole oil gas 64 chromatography areas and calculated weights as used in the pseudo compound data presented inFigure 7. The y-axis 2080 represents the concentration in terms of weight percent of eachnormal-C6 to normal-C38 compound found in the liquid phase. The x-axis 2081 contains theidentity of each normal alkane hydrocarbon compound from normal&amp;#1470;C6 to normal-C38. The datapoints occurring on line 2082 represent the weight percent of each normal-C6 to normal-C38hydrocarbon compound for the unstressed experiment of Example 1. The data points occurringon line 2083 represent the weight percent of each normal-C6 to normal-C38 hydrocarboncompound for the 400 psi stressed experiment of Example 3. While the data points occurring online 2084 represent the weight percent of each normal&amp;#1470;C6 to normal&amp;#1470;C38 hydrocarbon compoundfor the 1,000 psi stressed experiment of Example 4. From Figure 11 it can be seen that thehydrocarbon liquid produced in the unstressed experiment, represented by data points on line2082, contains a greater weight percentage of hydrocarbon compounds in the normal-C12 tonormal-C30 compound range, both as compared to the 400 psi stress experiment hydrocarbonliquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data pointsoccurring on line 2083, it is apparent that the intermediate level 400 psi stress experimentproduced a hydrocarbon liquid having normal-C12 to normal-C30 compound concentrationsbetween the unstressed experiment represented by line 2082 and the 1,000 psi stressedexperiment represented by line 2084. Lastly, it is apparent that the high level 1,000 psi stressexperiment produced a hydrocarbon liquid having normal-Cl 2 to normal-C30 compoundconcentrations less than both the unstressed experiment represented by line 2082 and the 400 psistressed experiment represented by line 2083. Thus pyrolyzing oil shale under increasing levelsof lithostatic stress appears to produce hydrocarbon liquids having lower concentrations ofnormal alkane hydrocarbons.

[0285] Figure 12 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal-C6 to normal&amp;#1470;C38 as compared to the normal&amp;#1470;C20 hydrocarboncompound for each of the three stress levels tested and analyzed in the laboratory experimentsdiscussed herein. The normal compound weight percentages were obtained as described forFigure 11. The y-axis 3000 represents the concentration in terms of weight ratio of each normal-C6 to normal&amp;#1470;C38 compound as compared to the normal&amp;#1470;C20 compound found in the liquidphase. The x-axis 3001 contains the identity of each normal alkane hydrocarbon compound ratiofrom normal-C6/normal-C20 to normal&amp;#1470;C38/normal&amp;#1470;C20. The data points occurring on line 3002represent the weight ratio of each normal&amp;#1470;C6 to normal-C38 hydrocarbon compound as comparedto the normal&amp;#1470;C20 compound for the unstressed experiment of Example 1. The data pointsoccurring on line 3003 represent the weight ratio of each normal&amp;#1470;C6 to normal-C38 hydrocarbon 65 compound as compared to the normal-C20 compound for the 400 psi stressed experiment ofExample 3. While the data points occurring on line 3004 represent the weight ratio of eachnormal-C6 to normal&amp;#1470;C38 hydrocarbon compound as compared to the normal&amp;#1470;C20 compound forthe 1,000 psi stressed experiment of Example 4. From Figure 12 it can be seen that theS hydrocarbon liquid produced in the unstressed experiment, represented by data points on line3002, contains a lower weight percentage of lighter normal alkane hydrocarbon components inthe normal-C6 to normal-C17 compound range as compared to the normal-C20 compound and agreater weight percentage of heavier hydrocarbon .components in the normal&amp;#1470;C22 to normal-C34compound range as compared to the normal-C20 compound, both as compared to the 400 psi10 stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid.Looking now at the data points occurring on line 3003, it is apparent that the intermediate level400 psi stress experiment produced a hydrocarbon liquid having normal&amp;#1470;C6 to normal-C17compound concentrations as compared to the normal&amp;#1470;C20 compound between the unstressed&amp;#1497; experiment represented by line 3002 and the 1,000 psi stressed experiment represented by line15 3004. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the normal-C22 to normal-C34 compound range as compared to the normal-C20 compound forthe intermediate stress level experiment represented by line 3003 falls between the unstressedexperiment (Line 3002) hydrocarbon liquid and the 1,000 psi stress experiment (Line 3004)hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced20 a hydrocarbon liquid having normal-C6 to normal&amp;#1470;C17 compound concentrations as compared to• the normal-C20 compound greater than both the unstressed experiment represented by line 3002and the 400 psi stressed experiment represented by line 3003. Further, it is apparent that theweight percentage of heavier hydrocarbon components in the normal-C22 to normal&amp;#1470;C34compound range as compared to the normal&amp;#1470;C20 compound for the high level stress experiment25 represented by line 3004 are less than both the unstressed experiment (Line 3002) hydrocarbonliquid and the 400 psi stress experiment (Line 3003) hydrocarbon liquid. This analysis furthersupports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stressproduces hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons.

[0286] Figure 13 is a graph of the weight percent of normal alkane hydrocarbon compounds30 occurring from normal-C6 to normal-C38 as compared to the normal-C25 hydrocarboncompound for each of the three stress levels tested and analyzed in the laboratory experimentsdiscussed herein. The normal compound weight percentages were obtained as described forFigure 11. The y-axis 3020 represents the concentration in terms of weight ratio of each normal-C6 to normal&amp;#1470;C38 compound as compared to the normal-C25 compound found in the liquid 66 phase. The x-axis 3021 contains the identity of each normal alkane hydrocarbon compound ratiofrom normal-C6/normal-C25 to normal-C38/normal-C25. The data points occurring on line 3022represent the weight ratio of each normal&amp;#1470;C6 to normal-C38 hydrocarbon compound as comparedto the normal&amp;#1470;C25 compound for the unstressed experiment of Example 1. The data pointsS occurring on line 3023 represent the weight ratio of each normal-C6 to normal-C38 hydrocarboncompound as compared to the normal-C2S compound for the 400 psi stressed experiment ofExample 3. While the data points occurring on line 3024 represent the weight ratio of eachnormal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C2S compound forthe 1,000 psi stressed experiment of Example 4. From Figure 13 it can be seen that the10 hydrocarbon liquid produced in the unstressed experiment, represented by data points on line3022,- contains a lower- weight percentage of lighter normal alkane hydrocarbon components inthe normal-C6 to normal-C24 compound range as compared to the normal&amp;#1470;C25 compound and agreater weight percentage of heavier hydrocarbon components in the normal-C26 to normal-C30compound range as compared to the normal-C25 compound, both as compared to the 400 psi15. stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid.Looking now at the data points occurring on line 3023, it is apparent that the intermediate level' 400 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal*C24compound concentrations as compared to the normal&amp;#1470;C25 compound between the unstressedexperiment represented by line 3022 and the 1,000 psi stressed experiment represented by line20 3024. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the normalrC26 to normal-C30 compound range as compared to the normal-C25 compound forthe intermediate stress level experiment represented by line 3023 falls between the unstressedexperiment (Line 3022) hydrocarbon liquid and the 1,000 psi stress experiment (Line 3024)hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced25 a hydrocarbon liquid having normal&amp;#1470;C6 to normal-C24 compound concentrations as compared tothe normal-C25 compound greater than both the unstressed experiment represented by line 3022and the 400 psi stressed experiment represented by line 3023. Further, it is apparent that theweight percentage of heavier hydrocarbon components in the normal-C26 to normal&amp;#1470;C30compound range as compared to the normal-C25 compound for the high level stress experiment30 represented by line 3024 are less than both the unstressed experiment (Line 3022) hydrocarbonliquid and the 400 psi stress experiment (Line 3023) hydrocarbon liquid. This analysis furthersupports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stressproduces hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons. 67 [0287] Figure 14 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal-C6 to normal-C38 as compared to the normal&amp;#1470;C29 hydrocarboncompound for each of the three stress levels tested and analyzed in the laboratory experimentsdiscussed herein. The normal compound weight percentages were obtained as described for 5 Figure 11. The y-axis 3040 represents the concentration in terms of weight ratio of each normal-C6 to normal-C38 compound as compared to the normal-C29 compound found in the liquidphase. The x-axis 3041 contains the identity of each normal alkane hydrocarbon compound ratiofrom normal-C6/normal-C29 to normal-C38/normal&amp;#1470;C29. The data points occurring on line 3042represent the weight ratio of each normal&amp;#1470;C6 to normal-C38 hydrocarbon compound as compared10 to the normal-C29 compound for the unstressed experiment of Example 1. The data pointsoccurring on line, 3043 represent the weight ratio of each normal-C6 to normal-C38 hydrocarboncompound as compared to the normal&amp;#1470;C29 compound for the 400 psi stressed experiment ofExample 3. While the data points occurring on line 3044 represent the weight ratio of eachnormal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C29 compound for15 the 1,000 psi stressed experiment of Example 4. From Figure 14 it can be seen that thehydrocarbon liquid produced in the unstressed experiment, represented by data points on line 3042, contains a lower weight percentage of lighter normal alkane hydrocarbon components inthe normaI&amp;#1470;C6 to normal-026 compound range as compared to the normal-029 compound, bothas compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress 20 . experiment hydrocarbon liquid. Looking now at the data points occurring on line 3043, it isapparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquidhaving normal-C6 to normal-C26 compound concentrations as compared to the normal-C29compound between the unstressed experiment represented by line 3042 and the 1,000 psi stressedexperiment represented by line 3044. Lastly, it is apparent that the high level 1,000 psi stress25 experiment produced a hydrocarbon liquid having normal-C6 to normal-C26 compoundconcentrations as compared to the normal-C29 compound greater than both the unstressedexperiment represented by line 3042 and the 400 psi stressed experiment represented by line 3043. This analysis further supports the relationship that pyroiyzing oil shale under increasinglevels of lithostatic stress produces hydrocarbon liquids having lower concentrations of normal 30 alkane hydrocarbons.

[0288] Figure 15 is a graph of the weight ratio of normal alkane hydrocarbon compounds topseudo components for each carbon number from C6 to C38 for each of the three stress levelstested and analyzed in the laboratory experiments discussed herein. The normal compound andpseudo component weight percentages were obtained as described for Figures 7 and 11. For 68 clarity, the normal alkane hydrocarbon and pseudo component weight percentages are taken as apercentage of the entire C3 to pseudo C38 whole oil gas chromatography areas and calculatedweights as used in the pseudo compound data presented in Figure 7. The y-axis 3060 representsthe concentration in terms of weight ratio of each normal&amp;#1470;C6/pseudo C6 to normal&amp;#1470;C38/pseudoC38 compound found in the liquid phase. The x-axis 3061 contains the identity of each normalalkane hydrocarbon compound to pseudo component ratio from normal-C6/pseudo C6 to normal-C38/pseudo C38. The data points occurring on line 3062 represent the weight ratio of eachnormal-C6/pseudo C6 to normal-C38/pseudo C38 ratio for the unstressed experiment of Example1. The data points occurring on line 3063 represent the weight ratio of each normal-C6/pseudoC6 to normal-C38/pseudo C38 ratio for the 400 psi stressed experiment of Example 3. While thedata points occurring on line 3064 represent the weight ratio of each normal-C6/pseudo C6 tononnal&amp;#1470;C38/pseudo C38 ratio for the 1,000 psi stressed experiment of Example 4. From Figure15 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented' by data points on line 3062, contains a greater weight percentage of normal alkane hydrocarboncompounds to pseudo components in the CIO to C26 range, both as compared to the 400 psistress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid.Looking now at the data points occurring on line 3063, it is apparent that the intermediate level400 psi stress experiment produced a hydrocarbon liquid having normal alkane hydrocarboncompound to pseudo component ratios in the CIO to C26 range between the unstressedexperiment represented by line 3062 and the 1,000 psi stressed experiment represented by line3064. Lastly, it is apparent that the high level 1,000 psi stress experiment produced ahydrocarbon liquid having normal alkane hydrocarbon compound to pseudo component ratios inthe CIO to C26 range less than both the unstressed experiment represented by line 3062 and the400 psi stressed experiment represented by line 3063. Thus pyrolyzing oil shale under increasinglevels of lithostatic stress appears to produce hydrocarbon liquids having lower concentrations ofnormal alkane hydrocarbons as compared to the total hydrocarbons for a given carbon numberoccurring between CIO and C26.

[0289] From the above-described data, it can be seen that heating and pyrolysis of oil shaleunder increasing levels of stress results in a condensable hydrocarbon fluid product that is lighter(i.e., greater proportion of lower carbon number compounds or components relative to highercarbon number compounds or components) and contains a lower concentration of normal alkanehydrocarbon compounds. Such a product may be suitable for refining into gasoline and distillateproducts. Further, such a product, either before or after further fractionation, may have utility asa feed stock for certain chemical processes. 69 [0290] In some embodiments, the produced hydrocarbon fluid includes a condensablehydrocarbon portion. In some embodiments the condensable hydrocarbon portion may have oneor more of a total C7 to total C20 weight ratio greater than 0.8, a total C8 to total C20 weightratio greater than 1.7, a total C9 to total C20 weight ratio greater than 2.5, a total CIO to total C20weight ratio greater than 2.8, a total Cl 1 to total C20 weight ratio greater than 2.3, a total C12 tototal C20 weight ratio greater than 2.3, a total C13 to total C20 weight ratio greater than 2.9, atotal C14 to total C20 weight ratio greater than 2.2, a total C15 to total C20 weight ratio greaterthan 2.2, and a total C16 to total C20 weight ratio greater than 1.6. In alternative embodimentsthe condensable hydrocarbon portion has one or more of a total C7 to total C20 weight ratiogreater than 2.5, a total C8 to total C20 weight ratio greater than 3.0, a total C9 to total C20weight ratio greater than 3.5, a total CIO to total C20 weight ratio greater than 3.5, a total Cll tototal C20 weight ratio greater than 3.0, and a total C12 to total C20 weight ratio greater than 3.0.In alternative embodiments the condensable hydrocarbon portion has one or more of a total C7 tototal C20 weight ratio greater than 3.5, a total C8 to total C20 weight ratio greater than 4.3, a·total C9 to total C20 weight ratio greater than 4.5, a total CIO to total C20 weight ratio greaterthan 4.2, a total Cll to total C20 weight ratio greater than 3.7, and a total C12 to total C20weight.ratio greater than 3.5. As used in this paragraph and in the claims, the phrase "one ormore" followed by a listing of different compound or component ratios with the last ratiointroduced by the conjunction "and" is meant to include a condensable hydrocarbon portion thathas at least one of the listed ratios or that has two or more, or three or more, or four or more, etc.,or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also haveadditional ratios of different compounds or components that are not included in a particularsentence or claim and still fall within the scope of such a sentence or claim. The embodimentsdescribed in this paragraph may be combined with any of the other aspects of the inventiondiscussed herein.

[0291] In some embodiments the condensable hydrocarbon portion has a total C7 to totalC20 weight ratio greater than 0.8. Alternatively, the condensable hydrocarbon portion may havea. total C7 to total C20 weight ratio greater than 1.0, greater than 1.5, greater than 2.0, greaterthan 2.5, greater than 3.5 or greater than 3.7. In alternative embodiments, the condensablehydrocarbon portion may have a total C7 to total C20 weight ratio less than 10.0, less than 7.0,less than 5.0 or less than 4.0. In some embodiments the condensable hydrocarbon portion has atotal C8 to total C20 weight ratio greater than 1.7. Alternatively, the condensable hydrocarbonportion may have a total C8 to total C20 weight ratio greater than 2.0, greater than 2.5, greaterthan 3.0, greater than 4.0, greater than 4.4, or greater than 4.6. In alternative embodiments, the WO 2008/143745 condensable hydrocarbon portion may have a total C8 to total C20 weight ratio less than 7.0 orless than 6.0. In some embodiments the condensable hydrocarbon portion has a total C9 to totalC20 weight ratio greater than 2.5. Alternatively, the condensable hydrocarbon portion may havea total C9 to total C20 weight ratio greater than 3.0, greater than 4.0, greater than 4.5, or greaterthan 4.7. In alternative embodiments, the condensable hydrocarbon portion may have a total C9to total C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensablehydrocarbon portion has a total CIO to total C20 weight ratio greater than 2.8. Alternatively, thecondensable hydrocarbon portion may have a total CIO to total C20 weight ratio greater than 3.0,.greater than 3.5, greater than 4.0, or greater than 4.3. In alternative embodiments, thecondensable hydrocarbon portion may have a total CIO to total C20 weight ratio less than 7.0 or.less than 6.0. In some embodiments the condensable hydrocarbon portion has a total Cl 1 to totalC20 weight ratio greater than 2.3. Alternatively, the condensable hydrocarbon portion may havea total Cll to total C20 weight ratio greater than 2.5, greater than 3.5, greater than 3.7, greaterthan 4.0. In alternative embodiments, the condensable hydrocarbon portion may have a total Cllto total C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensablehydrocarbon portion has a total C12 to total C20 weight ratio greater than 2.3. Alternatively, thecondensable hydrocarbon portion may have a total C12 to total C20 weight ratio greater than 2.5,greater than 3.0, greater than 3.5, or greater than 3.7. In alternative embodiments, thecondensable hydrocarbon portion may have a total C12 to total C20 weight ratio less than 7.0 orless than 6.0. In some embodiments the condensable hydrocarbon portion has a total C13 to totalC20 weight ratio greater than 2.9. Alternatively, the condensable hydrocarbon portion may havea total C13 to total C20 weight ratio greater than 3.0, greater than 3.1, or greater than 3.2. Inalternative embodiments, the condensable hydrocarbon portion may have a total C13 to total C20weight ratio less than 6.0 or less than 5.0. In some embodiments the condensable hydrocarbonportion has a total C14 to total C20 weight ratio greater than 2.2. Alternatively, the condensablehydrocarbon portion may have a total C14 to total C20 weight ratio greater than 2.5, greater than2.6, or greater than 2.7. In alternative embodiments, the condensable hydrocarbon portion mayhave a total C14 to total C20 weight ratio less than 6.0 or less than 4.0. In some embodimentsthe condensable hydrocarbon portion has a total C15 to total C20 weight ratio greater than 2.2.Alternatively, the condensable hydrocarbon portion may have a total C15 to total C20 weightratio greater than 2.3, greater than 2.4, or greater than 2.6. In alternative embodiments, thecondensable hydrocarbon portion may have a total C15 to total C20 weight ratio less than 6.0 orless than 4.0. In some embodiments the condensable hydrocarbon portion has a total C16 to totalC20 weight ratio greater than 1.6. Alternatively, the condensable hydrocarbon portion may have 71 a total C16 to total C20 weight ratio greater than 1.8, greater than 2.3, or greater than 2.5. Inalternative embodiments, the condensable hydrocarbon portion may have a total C16 to total C20weight ratio less than 5.0 or less than 4.0. Certain features of the present invention are describedin terms of a set of numerical upper limits (e.g. "less than") and a set of numerical lower limits(e.g. "greater than") in the preceding paragraph. It should be appreciated that ranges formed byany combination.of these limits are within the scope of the invention unless otherwise indicated.The embodiments described in this paragraph may be combined with any of the other aspects ofthe invention discussed herein.

[0292] In some embodiments the condensable hydrocarbon portion may have the one or moreof a total C7 to total C25 weight ratio greater than 2.0, a total C8 to total C25 weight ratio greaterthan 4.5, a total C9 to total C25 weight ratio greater than 6.5, a total CIO to total C25 weight ratiogreater than 7.5, a total Cll to total C25 weight ratio greater than 6.5, a total C12 to total C25weight ratio greater than 6.5, a total C13 to total C25 weight ratio greater than 8.0, a total C14 tototal C25 weight ratio greater than 6.0, a total Cl5 to total C25 weight ratio greater than 6.0; atotal C16 to total C25 weight ratio greater than 4.5, a total C17 to total C25 weight ratio greaterthan 4.8, and a total C18 to total C25 weight ratio greater than 4.5. In alternative embodimentsthe condensable hydrocarbon portion has one or more of a total C7 to total C25 weight ratiogreater than 7.0, a total C8 to total C25 weight ratio greater than 10.0, a total C9 to total C25weight ratio greater than 10.0, a total CIO to total C25 weight ratio greater than 10.0, a total Cllto total C25 weight ratio greater than 8.0, and a total Cl2 to total C25 weight ratio greater than 8.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a totalC7 to total C25 weight ratio greater than 13.0, a total C8 to total C25 weight ratio greater than 17.0, a total C9 to total C25 weight ratio greater than 17.0, a total CIO to total C25 weight ratiogreater than 15.0, a total Cll to total C25 weight ratio greater than 14.0, and a total C12 to totalC25 weight ratio greater than 13.0. As used in this paragraph and in the claims, the phrase "oneor more" followed by a listing of different compound or component ratios with the last ratiointroduced by the conjunction "and" is meant to include a condensable hydrocarbon portion thathas at least one of the listed ratios or that has two or more, or three or more, or four or more, etc.,or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also haveadditional ratios of different compounds or components that are not included in a particularsentence or claim and still fall within the scope of such a sentence or claim. The embodimentsdescribed in this paragraph may be combined with any of the other aspects of the inventiondiscussed herein. WO 2008/143745 [0293] In some embodiments the condensable hydrocarbon portion has a total C7 to totalC25 weight ratio greater than 2.0. Alternatively, the condensable hydrocarbon portion may havea total C7 to total C25 weight ratio greater than 3.0, greater than 5.0, greater than 10.0, greaterthan 13.0, or greater than 15.0. In alternative embodiments, the condensable hydrocarbon portionmay have a total C7 to total C25 weight ratio less than 30.0 or less than 25.0. In someembodiments the condensable hydrocarbon portion has a total C8 to total C25 weight ratiogreater than 4.5. Alternatively, the condensable hydrocarbon portion may have a total C8 to totalC25 weight ratio greater than 5.0, greater than 7.0, greater than 10.0, greater than 15.0, or greaterthan 17.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C8to total C25 weight ratio less than 35.0, or less than 30.0. In some embodiments the condensablehydrocarbon portion has a total C9 to total C25 weight ratio greater than 6.5. Alternatively, thecondensable hydrocarbon portion may have a total C9 to total C25 weight ratio greater than 8.0,greater than 10.0, greater than 15.0, greater than 17.0, or greater than 19.0. In alternativeembodiments, the condensable hydrocarbon portion may have a total C9 to total C25 weight ratioless than 40.0 or less than 35.0. In some embodiments the condensable hydrocarbon portion hasa total CIO to total C25 weight ratio greater than 7.5. Alternatively, the condensablehydrocarbon portion may have a total CIO to total C25 weight ratio greater than 10.0, greaterthan 14.0, or greater than 17.0. In alternative embodiments, the condensable hydrocarbon portionmay have a total CIO to total C25 weight ratio less than 35.0 or less than 30.0. In someembodiments the condensable hydrocarbon portion has a total Cll to total C25 weight ratiogreater than 6.5. Alternatively, the condensable hydrocarbon portion may have a total Cll tototal C25 weight ratio greater than 8.5, greater than 10.0, greater than 12.0, or greater than 14.0.In alternative embodiments, the condensable hydrocarbon portion may have a total Cll to totalC25 weight ratio less than 35.0 or less than 30.0. In some embodiments the condensablehydrocarbon portion has a total C12 to total C25 weight ratio greater than 6.5. Alternatively, thecondensable hydrocarbon portion may have a total C12 to total C25 weight ratio greater than 8.5,a total C12 to total C25 weight ratio greater than 10.0, greater than 12.0, or greater than 14.0. Inalternative embodiments, the condensable hydrocarbon portion may have a total C12 to total C25weight ratio less than 30.0 or less than 25.0. In some embodiments the condensable hydrocarbonportion has a total C13 to total C25 weight ratio greater than 8.0. Alternatively, the condensablehydrocarbon portion may have a total C13 to total C25 weight ratio greater than 10.0, greaterthan 12.0, or greater than 14.0. In alternative embodiments, the condensable hydrocarbon portionmay have a total Cl3 to total C25 weight ratio less than 25.0 or less than 20.0. In someembodiments the condensable hydrocarbon portion has a total C14 to total C25 weight ratio 73 greater than 6.0. Alternatively, the condensable hydrocarbon portion may have a total C14 tototal C2S weight ratio greater than 8.0, greater than 10.0, or greater than 12.0. In alternativeembodiments, the condensable hydrocarbon portion may have a total C14 to total C2S weightratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portionhas a total Cl5 to total C25 weight ratio greater than 6.0. Alternatively, the condensablehydrocarbon portion may have a total C15 to total C25 weight ratio greater than 8.0, or greaterthan 10.0. In alternative embodiments, the condensable hydrocarbon portion may have a total05 to total C25 weight ratio less than 25.0 or less than 20.0. In some embodiments thecondensable hydrocarbon portion has a total C16 to total C25 weight ratio greater than 4.5.Alternatively, the condensable hydrocarbon portion may have a total C16 to total C25 weightratio greater than 6.0, greater than 8.0, or greater than 10.0. In alternative embodiments, thecondensable hydrocarbon portion may have a total C16 to total C25 weight ratio less than 20.0 orless than 15.0. In some embodiments the condensable hydrocarbon portion has a total C17 tototal C25 weight ratio greater than 4.8. Alternatively, the condensable hydrocarbon portion mayhave a total C17 to total C25 weight ratio greater than 5.5 or greater than 7.0. In alternativeembodiments, the condensable hydrocarbon portion may have a total C17 to total C25 weightratio less than 20.0. In some embodiments the condensable hydrocarbon portion has a total Cl8to total C25 weight ratio greater than 4.5. Alternatively, the condensable hydrocarbon portionmay have a total C18 to total C25 weight ratio greater than 5.0 or greater than 5.5. In alternativeembodiments, the condensable hydrocarbon portion may have a total C18 to total C25 weightratio less than 15.0. Certain features of the present invention are described in terms of a set ofnumerical upper limits (e.g. "less than”) and a set of numerical lower limits (e.g. "greater than")in the preceding paragraph. It should be appreciated that ranges formed by any combination ofthese limits are within the scope of the invention unless otherwise indicated. The embodimentsdescribed in this paragraph may be combined with any of the other aspects of the inventiondiscussed herein.

[0294] In some embodiments the condensable hydrocarbon portion may have the one or moreof a total C7 to total C29 weight ratio greater than 3.5, a total C8 to total C29 weight ratio greaterthan 9.0, a total C9 to total C29 weight ratio greater than 12.0, a total CIO to total C29 weightratio greater than 15.0, a total Cll to total C29 weight ratio greater than 13.0, a total C12 to totalC29 weight ratio greater than 12.5, and a total C13 to total C29 weight ratio greater than 16.0, atotal C14 to total C29 weight ratio greater than 12.0, a total C15 to total C29 weight ratio greaterthan 12.0, a total C16 to total C29 weight ratio greater than 9.0, a total C17 to total C29 weightratio greater than 10.0, a total 08 to total C29 weight ratio greater than 8.8, a total 09 to total 74 C29 weight ratio greater than 7.0, a total C20 to total C29 weight ratio greater than 6.0, a totalC21 to total C29 weight ratio greater than 5.5, and a total C22 to total C29 weight ratio greaterthan 4.2. In alternative embodiments the condensable hydrocarbon portion has one or more of atotal C7 to total C29 weight ratio greater than 16.0, a total C8 to total C29 weight ratio greaterthan 19.0, a total C9 to total C29 weight ratio greater than 20.0, a total CIO to total C29 weightratio greater than 18.0, a total Cll to total C29 weight ratio greater than 16.0, a total C12 to totalC29 weight ratio greater than 15.0, and a total C13 to total C29 weight ratio greater than 17.0, atotal 04 to total C29 weight ratio greater than 13.0, a total 05 to total C29 weight ratio greaterthan 13.0, a total 06 to total C29 weight ratio greater than 10.0, a total 07 to total C29 weightratio greater than 11.0, a total 08 to total C29 weight ratio greater than 9.0, a total 09 to totalC29 weight ratio greater than 8.0, a total C20 to total C29 weight ratio greater than 6.5, and atotal C21 to total C29 weight ratio greater than 6.0. In alternative embodiments the condensablehydrocarbon portion has one or more of a total C7 to total C29 weight ratio greater than 24.0, atotal C8 to total C29 weight ratio greater than 30.0, a total C9 to total C29 weight ratio greaterthan 32.0, a total CIO to total C29 weight ratio greater than 30.0, a total Cll to total C29 weight·ratio greater than 27.0, a total C12 to total C29 weight ratio greater than 25.0, and a total C13 tototal C29 weight ratio greater than 22.0, a total C14 to total C29 weight ratio greater than 18.0, atotal C15 to total C29 weight ratio greater than 18.0, a total C16 to total C29 weight ratio greaterthan 16.0, a total C17 to total C29 weight ratio greater than 13.0, a total C18 to total C29 weightratio greater than 10.0, a total C19 to total C29 weight ratio greater than 9.0, and a total C20 tototal C29 weight ratio greater than 7.0. As used in this paragraph and in the claims, the phrase"one or more" followed by a listing of different compound or component ratios with the last ratiointroduced by the conjunction "and" is meant to include a condensable hydrocarbon portion thathas at least one of the listed ratios or that has two or more, or three or more, or four or more, etc.,or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also haveadditional ratios of different compounds or components that are not included in a particularsentence or claim and still fall within the scope of such a sentence or claim. The embodimentsdescribed in this paragraph may be combined with any of the other aspects of the inventiondiscussed herein.

[0295] In some embodiments the condensable hydrocarbon portion has a total C7 to totalC29 weight ratio greater than 3.5. Alternatively, the condensable hydrocarbon portion may havea total C7 to total C29 weight ratio greater than 5.0, greater than 10.0, greater than 18.0, greaterthan 20.0, or greater than 24.0. In alternative embodiments, the condensable hydrocarbon portionmay have a total C7 to total C29 weight ratio less than 60.0 or less than 50.0. In some PCIVUS2008/005008 75 WO 2008/143745 embodiments the condensable hydrocarbon portion has a total C8 to total C29 weight ratiogreater than 9.0. Alternatively, the condensable hydrocarbon portion may have a total C8 to totalC29 weight ratio greater than 10.0, greater than 18.0, greater than 20.0, greater than 25.0, orgreater than 30.0. In alternative embodiments, the condensable hydrocarbon portion may have atotal C8 to total C29 weight ratio less than 85.0 or less than 75.0. In some embodiments thecondensable hydrocarbon portion has a total C9 to total C29 weight ratio greater than 12.0.Alternatively, the condensable hydrocarbon portion may have a total C9 to total C29 weight ratiogreater than 15.0, greater than 20.0, greater than 23.0, greater than 27.0, or greater than 32.0. Inalternative embodiments, the condensable hydrocarbon portion may have a total C9 to total C29weight ratio less than 85.0 or less than 75.0. In some embodiments the condensable hydrocarbonportion has a total CIO to total C29 weight ratio greater than 15.0. Alternatively, the condensablehydrocarbon portion may have a total CIO to total C29 weight ratio greater than 18.0, greaterthan 22.0, or greater than 28.0. In alternative embodiments, the condensable hydrocarbon portionmay have a total CIO to total C29 weight ratio less than 80.0 or less than 70.0. In someembodiments the condensable hydrocarbon portion has a total Cll to total C29 weight ratiogreater than 13.0. Alternatively, the condensable hydrocarbon portion may have a total Cll tototal C29 weight ratio greater than 16.0, greater than 18.0, greater than 24.0, or greater than 27.0.In alternative embodiments, the condensable hydrocarbon portion may have a total Cll to totalC29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensablehydrocarbon portion has a total C12 to total C29 weight ratio greater than 12.5. Alternatively,the condensable hydrocarbon portion may have a total Cl 2 to total C29 weight ratio greater than14.5, greater than 18.0, greater than 22.0, or greater than 25.0. In alternative embodiments, thecondensable hydrocarbon portion may have a total C12 to total C29 weight ratio less than 75.0 orless than 65.0. In some embodiments the condensable hydrocarbon portion has a total C13 tototal C29 weight ratio greater than 16.0. Alternatively, the condensable hydrocarbon portion mayhave a total C13 to total C29 weight ratio greater than 18.0, greater than 20.0, or greater than 22.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C13 tototal C29 weight ratio less than 70.0 or less than 60.0. In some embodiments the condensablehydrocarbon portion has a total C14 to total C29 weight ratio greater than 12.0. Alternatively,the condensable hydrocarbon portion may have a total C14 to total C29 weight ratio greater than 14.0. greater than 16.0, or greater than 18.0. In alternative embodiments, the condensablehydrocarbon portion may have a total C14 to total C29 weight ratio less than 60.0 or less than 50.0. In some embodiments the condensable hydrocarbon portion has a total Cl 5 to total C29weight ratio greater than 12.0. Alternatively, the condensable hydrocarbon portion may have a 76 total C15 to total C29 weight ratio greater than 15.0 or greater than 18.0. In alternativeembodiments, the condensable hydrocarbon portion may have a total C15 to total C29 weightratio less than 60.0 or less than 50.0. In some embodiments the condensable hydrocarbon portionhas a total C16 to total C29 weight ratio greater than 9.0. Alternatively, the condensable5 hydrocarbon portion may have a total C16 to total C29 weight ratio greater than 10.0, greaterthan 13.0, or greater than 16.0. In alternative embodiments, the condensable hydrocarbon portionmay have a total C16 to total C29 weight ratio less than 55.0 or less than 45.0. In someembodiments the condensable hydrocarbon portion has a total C17 to total C29 weight ratiogreater than 10.0. Alternatively, the condensable hydrocarbon portion may have a total C17 to10 total C29 weight ratio greater than 11.0 or greater than 12.0. In alternative embodiments, thecondensable hydrocarbon portion may have a total C17 to total C29 weight ratio less than 45.0.In some embodiments the condensable hydrocarbon portion has a total C18 to total C29 weightratio greater than 8.8. Alternatively, the condensable hydrocarbon portion may have a total Cl8to total C29 weight ratio greater than 9.0 or greater than 10.0. In alternative embodiments, the15 condensable hydrocarbon portion may have a total C18 to total C29 weight ratio less than 35.0.In some embodiments the condensable hydrocarbon portion has a total C19 to total C29 weightratio greater than 7.0. Alternatively, the condensable hydrocarbon portion may have a total C19to total C29 weight ratio greater than 8.0 or greater than 9.0. In alternative embodiments, thecondensable hydrocarbon portion may have a total C19 to total C29 weight ratio less than 30.0.20 Certain features of the present invention are described in terms of a set of numerical upper limits(e:g. "less than") and a set of numerical lower limits (e.g. "greater than") in the precedingparagraph. It should be appreciated that ranges formed by any combination of these limits arewithin the scope of the invention unless otherwise indicated. The embodiments described in thisparagraph may be combined with any of the other aspects of the invention discussed herein. 25 [0296] In some embodiments the condensable hydrocarbon portion may have the one or more of a total C9 to total C20 weight ratio between 2.5 and 6.0, a total CIO to total C20 weight ratiobetween 2.8 and 7.3, a total Cll to total C20 weight ratio between 2.6 and 6.5, a total C12 tototal C20 weight ratio between 2.6 and 6.4 and a total C13 to total C20 weight ratio between 3.2and 8.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a30 total C9 to total C20 weight ratio between 3.0 and 5.5, a total CIO to total C20 weight ratiobetween 3.2 and 7.0, a total Cll to total C20 weight ratio between 3.0 and 6.0, a total C12 tototal C20 weight ratio between 3.0 and 6.0, and a total C13 to total C20 weight ratio between 3.3and 7.0. In alternative embodiments the condensable hydrocarbon portion has one or more of atotal C9 to total C20 weight ratio between 4.6 and 5.5, a total CIO to total C20 weight ratio 77 between 4.2 and 7.0, a total Cll to total C20 weight ratio between 3.7 and 6.0, a total C12 tototal C20 weight ratio between 3.6 and 6.0, and a total C13 to total C20 weight ratio between 3.4and 7.0. As used in this paragraph and in the claims, the phrase "one or more" followed by alisting of different compound or component ratios with the last ratio introduced by theconjunction "and" is meant to include a condensable hydrocarbon portion that has at least one ofthe listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listedratios. Further, a particular condensable hydrocarbon portion may also have additional ratios ofdifferent compounds or components that are not included in a particular sentence or claim andstill fall within the scope of such a sentence or claim. The embodiments described in thisparagraph may be combined with any of the other aspects of the invention discussed herein.

[0297] In some embodiments the condensable hydrocarbon portion has a total C9 to totalC20 weight ratio between 2.5 and 6.0. Alternatively, the condensable hydrocarbon portion mayhave a total C9 to total C20 weight ratio between 3.0 and 5.8, between 3.5 and 5.8, between 4.0and 5.8, between 4.5 and 5.8, between 4.6 and 5.8, or between 4.7 and 5.8. In someembodiments the condensable hydrocarbon portion has a total CIO to total C20 weight ratiobetween 2.8 and 7.3. Alternatively, the condensable hydrocarbon portion may have a total CIOto total C20 weight ratio between 3.0 and 7.2, between 3.5 and 7.0, between 4.0 and 7.0, between4.2 and 7.0, between 4.3 and 7.0, or between 4.4 and 7.0. In some embodiments the condensablehydrocarbon portion has a total Cll to total C20 weight ratio between 2.6 and 6.5. Alternatively,the condensable hydrocarbon portion may have a total Cll to total C20 weight ratio between 2.8and 6.3, between 3.5 and 6.3, between 3.7 and 6.3, between 3.8 and 6.3, between 3.9 and 6.2, orbetween 4.0 and 6.2. In some embodiments the condensable hydrocarbon portion has a total C12to total C20 weight ratio between 2.6 and 6.4. Alternatively, the condensable hydrocarbonportion may have a total C12 to total C20 weight ratio between 2.8 and 6.2, between 3.2 and 6.2,between 3.5 and 6.2, between 3.6 and 6.2, between 3.7 and 6.0, or between 3.8 and 6.0. In someembodiments the condensable hydrocarbon portion has a total C13 to total C20 weight ratiobetween 3.2 and 8.0. Alternatively, the condensable hydrocarbon portion may have a total C13to total C20 weight ratio between 3.3 and 7.8, between 3.3 and 7.0, between 3.4 and 7.0, between3.5 and 6.5, or between 3.6 and 6.0. The embodiments described in this paragraph may becombined with any of the other aspects of the invention discussed herein.

[0298] In some embodiments the condensable hydrocarbon portion may have one or more ofa total CIO to total C25 weight ratio between 7.1 and 24.5, a total Cll to total C25 weight ratiobetween 6.5 and 22.0, a total C12 to total C25 weight ratio between 6.5 and 22.0, and a total C13 78 to total C25 weight ratio between 8.0 and 27.0. In alternative embodiments the condensablehydrocarbon portion has one or more of a total CIO to total C25 weight ratio between 10.0 and 24.0, a total Cl 1 to total C25 weight ratio between 10.0 and 21.5, a total C12 to total C25 weightratio between 10.0 and 21.5, and a total C13 to total C25 weight ratio between 9.0 and 25.0. Inalternative embodiments the condensable hydrocarbon portion has one or more of a total CIO tototal C25 weight ratio between 14.0 and 24.0, a total Cll to total C25 weight ratio between 12.5and 21.5, a total C12 to total C25 weight ratio between 12.0 and 21.5, and a total C13 to totalC25 weight ratio between 10.5 and 25.0. As used in this paragraph and in the claims, the phrase"one or more" followed by a listing of different compound or component ratios with the last ratiointroduced by the conjunction "and" is meant to include a condensable hydrocarbon portion thathas at least one of the listed ratios or that has two or more, or three or more, or four or more, etc.,or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also haveadditional ratios of different compounds or components that are not included in a particularsentence or claim and still fall within the scope of such a sentence or claim. The embodimentsdescribed in this paragraph may be combined with any of the other aspects of the inventiondiscussed herein.

[0299] In some embodiments the condensable hydrocarbon portion has a total CIO to totalC25 weight ratio between 7.1 and 24.5. Alternatively, the condensable hydrocarbon portion mayhave a total CIO to total C25 weight ratio between 7.5 and 24.5, between 12.0 and 24.5, between13.8 and 24.5, between 14.0 and 24.5, or between 15.0 and 24.5. In some embodiments thecondensable hydrocarbon portion has a total Cll to total C25 weight ratio between 6.5 and 22.0.Alternatively, the condensable hydrocarbon portion may have a total Cll to total C25 weightratio between 7.0 and 21.5, between 10.0 and 21.5, between 12.5 and 21.5, between 13.0 and21.5, between 13.7 and 21.5, or between 14.5 and 21.5. In some embodiments the condensablehydrocarbon portion has a total C12 to total C25 weight ratio between 10.0 and 21.5.Alternatively, the condensable hydrocarbon portion may have a total C12 to total C25 weightratio between 10.5 and 21.0, between 11.0 and 21.0, between 12.0 and 21.0, between 12.5 and 21.0, between 13.0 and 21.0, or between 13.5 and 21.0. In some embodiments the condensablehydrocarbon portion has a total C13 to total C25 weight ratio between 8.0 and 27.0.Alternatively, the condensable hydrocarbon portion may have a total C13 to total C25 weightratio between 9.0 and 26.0, between 10.0 and 25.0, between 10.5 and 25.0, between 11.0 and 25.0, or between 11.5 and 25.0. The embodiments described in this paragraph may be combinedwith any of the other aspects of the invention discussed herein. 79 [0300] In some embodiments the condensable hydrocarbon portion may have one or more ofa total CIO to total C29 weight ratio between 15.0 and 60.0, a total Cll to total C29 weight ratiobetween 13.0 and 54.0, a total C12 to total C29 weight ratio between 12.5 and 53.0, and a totalC13 to total C29 weight ratio between 16.0 and 65.0. In alternative embodiments the5 condensable hydrocarbon portion has one or more of a total CIO to total C29 weight ratio between 17.0 and 58.0, a total Cll to total C29 weight ratio between 15.0 and 52.0, a total C12to total C29 weight ratio between 14.0 and 50.0, and a total C13 to total C29 weight ratiobetween 17.0 and 60.0. In alternative embodiments the condensable hydrocarbon portion hasone or more of a total CIO to total C29 weight ratio between 20.0 and 58.0, a total Cll to total10 C29 weight ratio between 18.0 and 52.0, a total C12 to total C29 weight ratio between 18.0 and 50.0, and a total C13 to total C29 weight ratio between 18.0 and 50.0. As used in this paragraphand in the claims, the phrase "one or more" followed by a listing of different compound orcomponent ratios with the last ratio introduced by the conjunction "and" is meant to include acondensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, 15 or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensablehydrocarbon portion may also have additional ratios of different compounds or components thatare not included in a particular sentence or claim and still fall within the scope of such a sentenceor claim. The embodiments described in this paragraph may be combined with any of the otheraspects of the invention discussed herein. 20 [0301] In some embodiments the condensable hydrocarbon portion has a total CIO to total C29 weight ratio between 15.0 and 60.0. Alternatively, the condensable hydrocarbon portionmay have a total CIO to total C29 weight ratio between 18.0 and 58.0, between 20.0 and 58.0,between 24.0 and 58.0, between 27.0 and 58.0, or between 30.0 and 58.0. In some embodimentsthe condensable hydrocarbon portion has a total Cll to total C29 weight ratio between 13.0 and25 54.0. Alternatively, the condensable hydrocarbon portion may have a total Cll to total C29 weight ratio between 15.0 and 53.0, between 18.0 and 53.0, between 20.0 and 53.0, between 22.0and 53.0, between 25.0 and 53.0, or between 27.0 and 53.0. In some embodiments thecondensable hydrocarbon portion has a total C12 to total C29 weight ratio between 12.5 and 53.0. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C2930 weight ratio between 14.5 and 51.0, between 16.0 and 51.0, between 18.0 and 51.0, between 20.0 and 51.0, between 23.0 and 51.0, or between 25.0 and 51.0. In some embodiments thecondensable hydrocarbon portion has a total C13 to total C29 weight ratio between 16.0 and. 65.0. Alternatively, the condensable hydrocarbon portion may have a total C13 to total C29weight ratio between 17.0 and 60.0, between 18.0 and 60.0, between 20.0 and 60.0, between 22.0 80 and 60.0, or between 25.0 and 60.0. The embodiments described in this paragraph may becombined with any of the other aspects of the invention discussed herein.

[0302] In some embodiments the condensable hydrocarbon portion may have one or more ofa normal&amp;#1470;C7 to normal-C20 weight ratio greater than 0.9, a normal-C8 to normal&amp;#1470;C20 weightratio greater than 2.0, a normal-C9 to normal-C20 weight ratio greater than 1.9, a normaI&amp;#1470;C10 tonormal-C20 weight ratio greater than 2.2, a normal-Cll to normal-C20 weight ratio greater than1.9, a normal-012 to normal-C20 weight ratio greater than 1.9, a normal&amp;#1470;C13 to normal-C20weight ratio greater than 2.3, a normal-C14 to normal-020 weight ratio greater than 1.8, anormal-C15 to normal-C20 weight ratio greater than 1.8, and normal-C16 to normal-C20 weightratio greater than 1.3. In alternative embodiments the condensable hydrocarbon portion has oneor more of a normal-C7 to normal-C20 weight ratio greater than 4.4, a normal-C8 to normal-C20weight ratio greater than 3.7, a normal&amp;#1470;C9 to normal-C20 weight ratio greater than 3.5, a normal-CIO to normal-C20 weight ratio greater than 3.4, a normal-Cll to normal-C20 weight ratiogreater than 3.0, and a normal-C12 to normal-C20 weight ratio greater than 2.7. In alternativeembodiments the condensable hydrocarbon portion has one or more of a normal-C7 to normal-C20 weight ratio greater than 4.9, a normal-C8 to normal-C20 weight ratio greater than 4.5, anormal-C9 to normal-C20 weight ratio greater than 4.4, a normal-ClO to normal-C20 weightratio greater than 4.1, a normal-Cll to normal-C20 weight ratio greater than 3.7, and a normal-Cl2 to normal-C20 weight ratio greater than 3.0. As used in this paragraph and in the claims, thephrase "one or more" followed by a listing of different compound or component ratios with thelast ratio introduced by the conjunction "and" is meant to include a condensable hydrocarbonportion that has at least one of the listed ratios or that has two or more, or three or more, or fouror more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portionmay also have additional ratios of different compounds or components that are not included in aparticular sentence or claim and still fall within the scope of such a sentence or claim. Theembodiments described in this paragraph may be combined with any of the other aspects of theinvention discussed herein.

[0303] In some embodiments the condensable hydrocarbon portion has a normal-C7 tonormal-C20 weight ratio greater than 0.9. Alternatively, the condensable hydrocarbon portionmay have a normal-C7 to normal-C20 weight ratio greater than 1.0, than 2.0, greater than 3.0,greater than 4.0, greater than 4.5, or greater than 5.0. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C7 to normal-C20 weight ratio less than8.0 or less than 7.0. In some embodiments the condensable hydrocarbon portion has a normal-08 WO 2008/143745 to normal-C20 weight ratio greater than 1.7. Alternatively, the condensable hydrocarbon portionmay have a normal-C8 to normal-C20 weight ratio greater than 2.0, greater than 2.5, greater than 3.0, greater than 3.5, greater than 4.0, or greater than 4.4. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C8 to normal*C20 weight ratio less than 8.0 or less than 7.0. In some embodiments the condensable hydrocarbon portion has a normal-C9to normal&amp;#1470;C20 weight ratio greater than 1.9. Alternatively, the condensable hydrocarbon portionmay have a normal-C9 to normal-C20 weight ratio greater than 2.0, greater than 3.0, greater than 4.0, or greater than 4.5. In alternative embodiments, the condensable hydrocarbon portion mayhave a normal-C9 to normal-C20 weight ratio less than 7.0 or less than 6.0. In someembodiments the condensable hydrocarbon portion has a normal-ClO to normal-C20 weight ratiogreater than 2.2. Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C10 tonormal-C20 weight ratio greater than 2.8, greater than 3.3, greater than 3.5, or greater than 4.0.In alternative embodiments, the condensable hydrocarbon portion may have a normal-CIO tonormal~C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensablehydrocarbon portion has a normal-Cl 1 to normal-C20 weight ratio greater than 1.9.Alternatively, the condensable hydrocarbon portion may have a normal-Cll to normal&amp;#1470;C20weight ratio greater than 2.5, greater than 3.0, greater than 3.5, or greater than 3.7. In alternativeembodiments, the condensable hydrocarbon portion may have a normal-Cll to normal-C20weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbonportion has a normal&amp;#1470;C12 to normal-C20 weight ratio greater than 1.9. Alternatively, thecondensable hydrocarbon portion may have a normal-C12 to normal-C20 weight ratio greaterthan 2.0, greater than 2.2, greater than 2.6, or greater than 3.0. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-Cl2 to normal-C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a normal-C13 to normal-C20 weight ratio greater than 2.3. Alternatively, the condensable hydrocarbonportion may have a normal-Cl3 to normal-C20 weight ratio greater than 2.5, greater than 2.7, orgreater than 3.0. In alternative embodiments, the condensable hydrocarbon portion may have anormal-C13 to normal-C20 weight ratio less than 6.0 or less than 5.0. In some embodiments thecondensable hydrocarbon portion has a normal-C14 to normal-C20 weight ratio greater than 1.8.Alternatively, the condensable hydrocarbon portion may have a normal-C14 to normal-C20weight ratio greater than 2.0, greater than 2.2, or greater than 2.5. In alternative embodiments,the condensable hydrocarbon portion may have a normal-C14 to normal-C20 weight ratio lessthan 6.0 or less than 4.0. In some embodiments the condensable hydrocarbon portion has anormal&amp;#1470;C15 to normal-C20 weight ratio greater than 1.8. Alternatively, the condensable 82 hydrocarbon portion may have a normal&amp;#1470;C15 to normal-C20 weight ratio greater than 2.0, greaterthan 2.2, or greater than 2.4. In alternative embodiments, the condensable hydrocarbon portionmay have a normal-Cl 5 to normal-C20 weight ratio less than 6.0 or less than 4.0. In someembodiments the condensable hydrocarbon portion has a normal-C16 to normal&amp;#1470;C20 weight ratiogreater than 1.3. Alternatively, the condensable hydrocarbon portion may have a normal-C16 tonormal-C20 weight ratio greater than 1.5, greater than 1.7, or greater than 2.0. In alternativeembodiments, the condensable hydrocarbon portion may have a normal-C16 to normal-C20weight ratio less than 5.0 or less than 4.0. Certain features of the present invention are describedin terms of a set of numerical upper limits (e.g. "less than") and a set of numerical lower limits(e.g. "greater than") in the preceding paragraph. It should be appreciated that ranges formed byany combination of these limits are within the scope of the invention unless otherwise indicated.The embodiments described in this paragraph may be combined with any of the other aspects ofthe invention discussed herein.

[0304] In some embodiments the condensable hydrocarbon portion may have one or more&amp;#1470; ofa normal-C7 to normal-C25 weight ratio greater than 1.9, a normal-C8 to normal&amp;#1470;C25 weightratio greater than 3.9, a normal-C9 to normal-C25 weight ratio greater than 3.7, a normal&amp;#1470;C10 tonormal-C25 weight ratio greater than 4.4, a normal-Cll to norma!-C25 weight ratio greater than3.8, a normal&amp;#1470;C12 to normal-C25 weight ratio greater than 3.7, a normal&amp;#1470;C13 to normal-C25weight ratio greater than 4.7, a normal-C14 to normal-C25 weight ratio greater than 3.7, anormal-C15 to normal-C25 weight ratio greater than 3.7, a normal&amp;#1470;C16 to normal-C25 weightratio greater than 2.5, a normal-C17 to normal-C25 weight ratio greater than 3.0, and a normal-Cl 8 to normal-C25 weight ratio greater than 3.4. In alternative embodiments the condensablehydrocarbon portion has one or more of a normal-C7 to normal-C25 weight ratio greater than 10,a normal&amp;#1470;C8 to normal-C25 weight ratio greater than 8.0, a normal-C9 to normal-C25 weightratio greater than 7.0, a normal-C 10 to normal-C25 weight ratio greater than 7.0, a normal-Cl 1 tonormal-C25 weight ratio greater than 7.0, and a normal&amp;#1470;C12 to normaI-C25 weight ratio greaterthan 6.0. In alternative embodiments the condensable hydrocarbon portion has one or more of anormal-C7 to normal-C25 weight ratio greater than 10.0, a normal-C8 to normal-C25 weightratio greater than 12.0, a normal-C9 to normal-C25 weight ratio greater than 11.0, a normal-C10to normal-C25 weight ratio greater than 11.0, a normal-Cll to normal-C25 weight ratio greaterthan 9.0, and a normal-C 12 to normal-C25 weight ratio greater than 8.0. As used in thisparagraph and in the claims, the phrase "one or more" followed by a listing of differentcompound or component ratios with the last ratio introduced by the conjunction "and" is meant toinclude a condensable hydrocarbon portion that has at least one of the listed ratios or that has two 83 or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particularcondensable hydrocarbon portion may also have additional ratios of different compounds orcomponents that are not included in a particular sentence or claim and still fall within the scopeof such a sentence or claim. The embodiments described in this paragraph may be combined5 with any of the other aspects of the invention discussed herein.

[0305] In some embodiments the condensable hydrocarbon portion has a normal-C7 tonormal-025 weight ratio greater than 1.9. Alternatively, the condensable hydrocarbon portionmay have a normal-C7 to normal-C25 weight ratio greater than 3.0, greater than 5.0, greater than 8.0, greater than 10.0, or greater than 13.0. In alternative embodiments, the condensable10 hydrocarbon portion may have a normal-C7 to normal&amp;#1470;C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a normal&amp;#1470;C8 tonormal-C25 weight ratio greater than 3.9. Alternatively, the condensable hydrocarbon portionmay have a normal-08 to normal-025 weight ratio greater than 4.5, greater than 6.0, greater than 8.0, greater than 10.0, or greater than 13.0. In alternative embodiments, the condensable15 hydrocarbon portion may have a normal-08 to normal-025 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a normal-09 tonormal-025 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portionmay have a normal-09 to normal-025 weight ratio greater than 4.5, greater than 7.0, greater than 10.0, greater than 12.0, or greater than 13.0. In alternative embodiments, the condensable20 hydrocarbon portion may have a normal-09 to normal-025 weight ratio less than 35.0 or less than 25.0. In some embodiments the: condensable hydrocarbon portion has a normal-CIO tonormal-025 weight ratio greater than 4.4. Alternatively, the condensable hydrocarbon portionmay have a normal-CIO to normal-025 weight ratio greater than 6.0, greater than 8.0, or greaterthan 11.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-25 CIO to normal-025 weight ratio less than 35.0 or less than 25.0. In some embodiments thecondensable hydrocarbon portion has a normal-Cll to normal-025 weight ratio greater than 3.8.Alternatively, the condensable hydrocarbon portion may have a normal-Cl 1 to normal-025weight ratio greater than 4.5, greater than 7.0, greater than 8.0, or greater than 10.0. Inalternative embodiments, the condensable hydrocarbon portion may have a normal-011 to30 normal-025 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensablehydrocarbon portion has a normal-012 to normal-025 weight ratio greater than 3.7.Alternatively, the condensable hydrocarbon portion may have a normal-012 to normal-025weight ratio greater than 4.5, greater than 6.0, greater than 7.0, or greater than 8.0. In alternativeembodiments, the condensable hydrocarbon portion may have a normal-012 to normal-025 WO 2008/143745 weight ratio less than 30.0 or less than 20.0. In some embodiments the condensable hydrocarbonportion has a normal-C13 to normal-C25 weight ratio greater than 4.7. Alternatively, thecondensable hydrocarbon portion may have a normal-C13 to normal-C25 weight ratio greaterthan 5.0, greater than 6.0, or greater than 7.5. In alternative embodiments, the condensablehydrocarbon portion may have a normal&amp;#1470;C13 to normal-C25 weight ratio less than 25.0 or lessthan 20.0. In some embodiments the condensable hydrocarbon portion has a normal-C14 tonormal-C25 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portionmay have a normal-C14 to normal&amp;#1470;C25 weight ratio greater than 4.5, greater than 5.5, or greaterthan 7.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C14 to normal-C25 weight ratio less than 25.0 or less than 20.0. In some embodiments thecondensable hydrocarbon portion has a normal-C15 to normal&amp;#1470;C25 weight ratio greater than 3.7.Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C15 to normal-C25weight ratio greater than 4.2 or greater than 5.0. In alternative embodiments, the condensablehydrocarbon portion may have a normal-C15 to normal&amp;#1470;C25 weight ratio less than 25.0 or lessthan 20.0. In some embodiments the condensable hydrocarbon portion has a normal-Cl 6 tonormal-C25 weight ratio greater than 2.5. Alternatively, the condensable hydrocarbon portionmay have a normal-C16 to normal-C25 weight ratio greater than 3.0, greater than 4.0, or greaterthan 5.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-Cl6 to normal-C25 weight ratio less than 20.0 or less than 15.0. In some embodiments thecondensable hydrocarbon portion has a normal-C17 to normal&amp;#1470;C25 weight ratio greater than 3.0.Alternatively, the condensable hydrocarbon portion may have a normal-Cl7 to normal-C25weight ratio greater than 3.5 or greater than 4.0. In alternative embodiments, the condensablehydrocarbon portion may have a normal-C17 to normal-C25 weight ratio less than 20.0. In someembodiments the condensable hydrocarbon portion has a normal-C18 to normal&amp;#1470;C25 weight ratiogreater than 3.4. Alternatively, the condensable hydrocarbon portion may have a normal-Cl8 tonormal-C25 weight ratio greater than 3.6 or greater than 4.0. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-Cl8 to normal-C25 weight ratio less than15.0. Certain features of the present invention are described in terms of a set of numerical upperlimits (e.g. "less than") and a set of numerical lower limits (e.g. "greater than") in the precedingparagraph. It should be appreciated that ranges formed by any combination of these limits arewithin the scope of the invention unless otherwise indicated. The embodiments described in thisparagraph may be combined with any of the other aspects of the invention discussed herein.

[0306] In some embodiments the condensable hydrocarbon portion may have one or more ofa normal-C7 to normal-C29 weight ratio greater than 18.0, a normal-C8 to normal-C29 weight WO 2008/143745 ratio greater than 16.0, a normal&amp;#1470;C9 to normal&amp;#1470;C29 weight ratio greater than 14.0, a normal-CIOto normal&amp;#1470;C29 weight ratio greater than 14.0, a normal-Cll to normal-C29 weight ratio greaterthan 13.0, a normal-C12 to normal-C29 weight ratio greater than 11.0, a normal&amp;#1470;C13 to normal-C29 weight ratio greater than 10.0, a normal&amp;#1470;C14 to normal&amp;#1470;C29 weight ratio greater than 9.0, anormal-C15 to normal-C29 weight ratio greater than 8.0, a normal&amp;#1470;C16 to normal-C29 weightratio greater than 8.0, a normal-C17 to normal-C29 weight ratio greater than 6.0, a normal-C18 tonormal&amp;#1470;C29 weight ratio greater than 6.0, a normal-C19 to normal&amp;#1470;C29 weight ratio greater than 5.0, a normal-C20 to normal&amp;#1470;C29 weight ratio greater than 4.0, a normal-C21 to normal-C29weight ratio greater than 3.6, and a normal-C22 to normal-C29 weight ratio greater than 2.8. Inalternative embodiments the condensable hydrocarbon portion has one or more of a normal-C7 tonormal&amp;#1470;C29 weight ratio greater than 20.0, a normal&amp;#1470;C8 to normal&amp;#1470;C29 weight ratio greater than 18.0, a normal&amp;#1470;C9 to normal-C29 weight ratio greater than 17.0, a normal&amp;#1470;C10 to normal-C29weight ratio greater than 16.0, a normal-Cll to normal-C29 weight ratio greater than 15.0, anormal-C12 to nbrmal-C29 weight ratio greater than 12.5, a normal&amp;#1470;C13 to normal-C29 weightratio greater than 11.0, a normal-C14 to normal-C29 weight ratio greater than 10.0, a normal-C15to normal-C29 weight ratio greater than 8.0, a normal-C16 to normal-C29 weight ratio greaterthan 8.0, a normal-C17 to normal-C29 weight ratio greater than 7.0, a normal-C18 to normal-C29weight ratio greater than 6.5, a normal-C19 to normal-C29 weight ratio greater than 5.5, anormaI-C20 to normal-C29 weight ratio greater than 4.5, and a normal-C21 to normal-C29weight ratio greater than 4.0. In alternative embodiments the condensable hydrocarbon portionhas one or more of a normal-C7 to normal-C29 weight ratio greater than 23.0, a normal-C8 tonormal-C29 weight ratio greater than 21.0, a normal-C9 to normal-C29 weight ratio greater than 20.0, a normal-CIO to normal-C29 weight ratio greater than 19.0, a normal-Cll to normal-C29weight ratio greater than 17.0, a normal-C12 to normal-C29 weight ratio greater than 14.0, anormal-Cl3 to normal-C29 weight ratio greater than 12.0, a normal-C14 to normal-C29 weightratio greater than 11.0, a normal&amp;#1470;C15 to normal-C29 weight ratio greater than 9.0, a normal-C16to normal-C29 weight ratio greater than 9.0, a normal-C17 to normal-C29 weight ratio greaterthan 7.5, a normal-C18 to normal-C29 weight ratio greater than 7.0, a normal-C19 to normal-C29weight ratio greater than 6.5, a normal-C20 to normal-C29 weight ratio greater than 4.8, and anormal-C21 to normal-C29 weight ratio greater than 4.5. As used in this paragraph and in theclaims, the phrase "one or more" followed by a listing of different compound or component ratioswith the last ratio introduced by the conjunction "and" is meant to include a condensablehydrocarbon portion that has at least one of the listed ratios or that has two or more, or three ormore, or four or more, etc., or all of the listed ratios. Further, a particular condensable 86 hydrocarbon portion may also have additional ratios of different compounds or components thatare not included in a particular sentence or claim and still fall within the scope of such a sentenceor claim. The embodiments described in this paragraph may be combined with any of the otheraspects of the invention discussed herein.

[0307] In some embodiments the condensable hydrocarbon portion has a normal&amp;#1470;C7 tonormal-C29 weight ratio greater than 18.0. Alternatively, the condensable hydrocarbon portionmay have a normal&amp;#1470;C7 to normal-C29 weight ratio greater than 20.0, greater than 22.0, greaterthan 25.0, greater than 30.0, or greater than 35.0. In alternative embodiments, the condensablehydrocarbon portion may have a normal-C7 to normal-C29 weight ratio less than 70.0 or lessthan 60.0. In some embodiments the condensable hydrocarbon portion has a normal-C8 tonormal-C29 weight ratio greater than 16.0. Alternatively, the condensable hydrocarbon portionmay have a normal-C8 to normal-C29 weight ratio greater than 18.0, greater than 22.0, greaterthan 25.0, greater than 27.0, or greater than 30.0. In alternative embodiments, the condensablehydrocarbon portion may have a normaIrC8 to normal-C29 weight ratio less than 85.0 or lessthan 75.0. In some embodiments the condensable hydrocarbon portion has a normal-C9 tonormal-C29 weight ratio greater than 14.0. Alternatively, the condensable hydrocarbon portionmay have a normal-C9 to normal-C29 weight ratio greater than 18.0, greater than •20.0, greaterthan 23.0, greater than 27.0, or greater than 30.0. In alternative embodiments, the condensablehydrocarbon portion may have a normal&amp;#1470;C9 to normal-C29 weight ratio less than .85.0 or lessthan 75.0. In some embodiments the condensable hydrocarbon portion has a normal-CIO tonormal-C29 weight ratio greater than 14.0. Alternatively, the condensable hydrocarbon portionmay have a normal-CIO to normal-C29 weight ratio greater than 20.0, greater than 25.0, orgreater than 30.0. In alternative embodiments, the condensable hydrocarbon portion may have anormal-CIO to normal-C29 weight ratio less than 80.0 or less than 70.0. In some embodimentsthe condensable hydrocarbon portion has a normal-Cll to normal-C29 weight ratio greater than13.0. Alternatively, the condensable hydrocarbon portion may have a normal-Cll to normal-C29 weight ratio greater than 16.0, greater than 18.0, greater than 24.0, or greater than 27.0. Inalternative embodiments, the condensable hydrocarbon portion may have a normal-Cll tonormal-C29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensablehydrocarbon portion has a normal-C12 to normal-C29 weight ratio greater than 11.0.Alternatively, the condensable hydrocarbon portion may have a normal-C12 to normal-C29weight ratio greater than 14.5, greater than 18.0, greater than 22.0, or greater than 25.0. Inalternative embodiments, the condensable hydrocarbon portion may have a normal-C12 tonormal-C29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensable WO 2008/143745 hydrocarbon portion has a normaI-C13 to normaI-C29 weight ratio greater than 10.0.Alternatively, the condensable hydrocarbon portion may have a normal-C13 to normal-C29weight ratio greater than 18.0, greater than 20.0, or greater than 22.0. In alternativeembodiments, the condensable hydrocarbon portion may have a normal-C13 to normal-C29weight ratio less than 70.0 or less than 60.0. In some embodiments the condensable hydrocarbonportion has a normal&amp;#1470;C14 to normal&amp;#1470;C29 weight ratio greater than 9.0. Alternatively, thecondensable hydrocarbon portion may have a normal-C14 to normal-C29 weight ratio greaterthan 14.0, greater than 16.0, or greater than 18.0. In alternative embodiments, the condensablehydrocarbon portion may have a normal&amp;#1470;C14 to normal-C29 weight ratio less than 60.0 or lessthan 50.0. In some embodiments the condensable hydrocarbon portion has a normal-C15 tonormal-C29 weight ratio greater than 8.0. Alternatively, the condensable hydrocarbon portionmay have a normal-C15 to normal-C29 weight ratio greater than 12.0 or greater than 16.0. Inalternative embodiments, the condensable hydrocarbon portion may have a norma)-C15 tonormal-C29 weight ratio less than 60.0 or less than S0.0. In some embodiments the condensablehydrocarbon portion has a normal-C16 to normal-C29 weight ratio greater than 8.0.Alternatively, the condensable hydrocarbon portion may have a normal-C16 to normal&amp;#1470;C29weight ratio greater than 10.0, greater than 13.0, or greater than 15.0. In alternativeembodiments, the condensable hydrocarbon portion may have a normal-C16 to normal-C29weight ratio less than 55.0 or less than 45.0. In some embodiments the condensable hydrocarbonportion has a normal-Cl7 to normal-C29 weight ratio greater than 6.0. Alternatively, thecondensable hydrocarbon portion may have a normal-C17 to normal-C29 weight ratio greaterthan 8.0 or greater than 12.0. In alternative embodiments, the condensable hydrocarbon portionmay have a normal-Cl7 to normal&amp;#1470;C29 weight ratio less than 45.0. In some embodiments thecondensable hydrocarbon portion has a normal&amp;#1470;C18 to normal-C29 weight ratio greater than 6.0.Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C18 to normal&amp;#1470;C29weight ratio greater than 8.0 or greater than 10.0. In alternative embodiments, the condensablehydrocarbon portion may have a normal-Cl8 to normal-C29 weight ratio less than 35.0. In someembodiments the condensable hydrocarbon portion has a normal-C19 to normal-C29 weight ratiogreater than 5.0. Alternatively, the condensable hydrocarbon portion may have a normal-C19 tonormal-C29 weight ratio greater than 7.0 or greater than 9.0. In alternative embodiments, thecondensable hydrocarbon portion may have a normal&amp;#1470;C19 to normal-C29 weight ratio less than30.0. In some embodiments the condensable hydrocarbon portion has a normal&amp;#1470;C20 to normal-C29 weight ratio greater than 4.0. Alternatively, the condensable hydrocarbon portion may havea normal-C20 to normal-C29 weight ratio greater than 6.0 or greater than 8.0. In alternative PCT7US2008/005008 embodiments, the condensable hydrocarbon portion may have a normal-C20 to normal&amp;#1470;C29weight ratio less than 30.0. In some embodiments the condensable hydrocarbon portion has anormal-C21 to normal-C29 weight ratio greater than 3.6. Alternatively, the condensablehydrocarbon portion may have a normal-C21 to normal-C29 weight ratio greater than 4.0 orgreater than 6.0. In alternative embodiments, the condensable hydrocarbon portion may have anormal-C21 to normal-C29 weight ratio less than 30.0. In some embodiments the condensablehydrocarbon portion has a normal&amp;#1470;C22 to normal-C29 weight ratio greater than 2.8.Alternatively, the condensable hydrocarbon portion may have a normal-C22 to normal&amp;#1470;C29weight ratio greater than 3.0. In alternative embodiments, the condensable hydrocarbon portionmay have a normal-C22 to normal&amp;#1470;C29 weight ratio less than 30.0. Certain features of thepresent invention are described in terms of a set of numerical upper limits (e.g. "less than") and aset of numerical lower limits (e.g. "greater than") in the preceding paragraph. It should beappreciated that ranges formed by any combination of these limits are within the scope of theinvention unless otherwise indicated. The embodiments described in this paragraph may becombined with any of the other aspects of the invention discussed herein.

[0308] In some embodiments the condensable hydrocarbon portion may have one or more ofa normal&amp;#1470;C10 to total CIO weight ratio less than 0.31, anormal-Cll to total Cll weight ratio lessthan 0.32, a normal&amp;#1470;C12 to total C12 weight ratio less than 0.29, a normal-C13 to total C13weight ratio less than 0.28, a normal-C14 to total C14 weight ratio less than 0.31, a normal-C15to total C15 weight ratio less than 0.27, a normal-C16 to total C16 weight ratio less than 0.31, anormal-C17 to total C17 weight ratio less than 0.31, a normal-C18 to total C18 weight ratio lessthan 0.37, normal-C19 to total C19 weight ratio less than 0.37, a normal&amp;#1470;C20 to total C20 weightratio less than 0.37, a normal-C21 to total C21 weight ratio less than 0.37, a normal-C22 to totalC22 weight ratio less than 0.38, normal&amp;#1470;C23 to total C23 weight ratio less than 0.43, a normal-C24 to total C24 weight ratio less than 0.48, and a normal-C25 to total C25 weight ratio less than0.S3. In alternative embodiments the condensable hydrocarbon portion has one or more of anormal-Cll to total Cll weight ratio less than 0.30, a normal-C12 to total C12 weight ratio lessthan 0.27, a normal-C13 to total C13 weight ratio less than 0.26, a normal-C14 to total C14weight ratio less than 0.29, a normal&amp;#1470;C15 to total C15 weight ratio less than 0.24, a normal-C16to total C16 weight ratio less than 0.25, a normal-C17 to total C17 weight ratio less than 0.29, anormal-C18 to total C18 weight ratio less than 0.31, normal-C19 to total C19 weight ratio lessthan 0.35, a normal-C20 to total C20 weight ratio less than 0.33, a normal-C21 to total C21weight ratio less than 0.33, a normal-C22 to total C22 weight ratio less than 0.35, normal-C23 tototal C23 weight ratio less than 0.40, a normal-C24 to total C24 weight ratio less than 0.45, and a 89 normal-C25 to total C25 weight ratio less than 0.49. In alternative embodiments the condensablehydrocarbon portion has one or more of a normal-Cll to total Cll weight ratio less than 0.28, anormal-C12 to total C12 weight ratio less than 0.25, a normal-C13 to total C13 weight ratio lessthan 0.24, a normal-C14 to total C14 weight ratio less than 0.27, a normal-C15 to total C155 weight ratio less than 0.22, a normal&amp;#1470;C16 to total C16 weight ratio less than 0.23, a normal-C17to total C17 weight ratio less than 0.25, a normal-C18 to total C18 weight ratio less than 0.28,normal-C19 to total C19 weight ratio less than 0.31, a normal-C20 to total C20 weight ratio lessthan 0.29, a normal&amp;#1470;C21 to total C21 weight ratio less than 0.30, a normal-C22 to total C22weight ratio less than 0.28, normal-C23 to total C23 weight ratio less than 0.33, a normal-C24 to10 total C24 weight ratio less than 0.40, and a normal-C25 to total C25 weight ratio less than 0.45.As used in this paragraph and in the claims, the phrase "one or more” followed by a listing of. different compound or component ratios with the last ratio introduced by the conjunction "and" ismeant to include a condensable hydrocarbon portion that has at least one of the listed ratios orthat has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a15 particular condensable hydrocarbon portion may also have additional ratios of differentcompounds or components that are not included in a particular sentence or claim and still fallwithin the scope of such a sentence or claim. The embodiments described in this paragraph maybe combined with any of the other aspects of the invention discussed herein.

[0309] In some embodiments the condensable hydrocarbon portion has a normal-CIO to total20 CIO weight ratio less than 0.31. Alternatively, the condensable hydrocarbon portion may have anormal-CIO to total CIO weight ratio less than 0.30 or less than 0.29. In alternativeembodiments, the condensable hydrocarbon portion may have a normal-CIO to total CIO weightratio greater than 0.15 or greater than 0.20. In some embodiments the condensable hydrocarbonportion has a normal-Cl 1 to total Cll weight ratio less than 0.32. Alternatively, the condensable25 hydrocarbon portion may have a normal-Cll to total Cll weight ratio less than 0.31, less than0.30, or less than 0.29. In alternative embodiments, the condensable hydrocarbon portion mayhave a normal-Cll to total Cll weight ratio greater than 0.15 or greater than 0.20. In someembodiments the condensable hydrocarbon portion has a normal-C12 to total C12 weight ratioless than 0.29. Alternatively, the condensable hydrocarbon portion may have a normal-Cl 2 to30 total C12 weight ratio less than 0.26, or less than 0.24. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-Cl2 to total C12 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has anormal-C13 to total C13 weight ratio less than 0.28. Alternatively, the condensable hydrocarbonportion may have a normal-Cl3 to total C13 weight ratio less than 0.27, less than 0.25, or less WO 2008/143745 than 0.23. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C13 to total C13 weight ratio greater than 0.10 or greater than 0.15. In some embodiments thecondensable hydrocarbon portion has a normal-C14 to total C14 weight ratio less than 0.31.Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C14 to total C14 weightratio less than 0.30, less than 0.28, or less than 0.26. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C14 to total C14 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has anormal-C15 to total C15 weight ratio less than 0.27. Alternatively, the condensable hydrocarbonportion may have a normal-C15 to total C15 weight ratio less than 0.26, less than 0.24, or lessthan 0.22. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C15 to total C15 weight ratio greater than 0.10 or greater than 0.15. In some embodiments thecondensable hydrocarbon portion has a normal-C16 to total C16 weight ratio less than 0.31.Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C16 to total C16 weightratio less than 0.29, less than 0.26, or less than 0.24. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C16 to total C16 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has anormal-C17 to total C17 weight ratio less than 0.31. Alternatively, the condensable hydrocarbonportion may have a normal-Cl7 to total C17 weight ratio less than 0.29, less than 0.27, or lessthan 0.25. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C17 to total C17 weight ratio greater than 0.10 or greater than 0.15. In some embodiments thecondensable hydrocarbon portion has a normal-C18 to total C18 weight ratio less than 0.37.Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C18 to total C18 weightratio less than 0.35, less than 0.31, or less than 0.28. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C18 to total C18 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has anormal&amp;#1470;C19 to total C19 weight ratio less than 0.37. Alternatively, the condensable hydrocarbonportion may have a normal&amp;#1470;C19 to total C19 weight ratio less than 0.36, less than 0.34, or lessthan 0.31. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C19 to total C19 weight ratio greater than 0.10 or greater than 0.15. In some embodiments thecondensable hydrocarbon portion has a normal-C20 to total C20 weight ratio less than 0.37.Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C20 to total C20 weightratio less than 0.35, less than 0.32, or less than 0.29. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C20 to total C20 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a 91 normal-C21 to total C21 weight ratio less than 0.37. Alternatively, the condensable hydrocarbonportion may have a normal-C21 to total C21 weight ratio less than 0.35, less than 0.32, or lessthan 0.30. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C21 to total C21 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the5 condensable hydrocarbon portion has a normal-C22 to total C22 weight ratio less than 0.38.Alternatively, the condensable hydrocarbon portion may have a normal&amp;#1470;C22 to total C22 weightratio less than 0.36, less than 0.34, or less than 0.30. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C22 to total C22 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a10 normal-C23 to total C23 weight ratio less than 0.43. Alternatively, the condensable hydrocarbonportion may have a normal-C23 to total C23 weight ratio less than 0.40, less than 0.35, or lessthan 0.29. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C23 to total C23 weight ratio greater than 0.15 or greater than 0.20. In some embodiments thecondensable hydrocarbon portion has a normal-C24 to total C24 weight ratio less than 0.48.15 Alternatively, the condensable hydrocarbon portion may have a normal-C24 to total C24 weightratio less than 0.46, less than 0.42, or less than 0.40. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-C24 to total C24 weight ratio greater than0.15 or greater than 0.20. In some embodiments the condensable hydrocarbon portion has anormal&amp;#1470;C25 to total C25 weight ratio less than 0.48. Alternatively, the condensable hydrocarbon20 portion may have a normal&amp;#1470;C25 to total C25 weight ratio less than 0.46, less than 0.42, or lessthan 0.40. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C25 to total C25 weight ratio greater than 0.20 or greater than 0.25. Certain features of thepresent invention are described in terms of a set of numerical upper limits (e.g. "less than") and aset of numerical lower limits (e.g. "greater than") in the preceding paragraph. It should be25 appreciated that ranges formed by any combination of these limits are within the scope of theinvention unless otherwise indicated. The embodiments described in this paragraph may becombined with any of the other aspects of the invention discussed herein.

[0310] The use of "total C_" (e.g., total CIO) herein and in the claims is meant to refer to theamount of a particular pseudo component found in a condensable hydrocarbon fluid determined30 as described herein, particularly as described in the section labeled "Experiments" herein. That is"total C_" is determined using the whole oil gas chromatography (WOGC) analysis methodologyaccording to the procedure described in the Experiments section of this application. Further,"total C_" is determined from the whole oil gas chromatography (WOGC) peak integrationmethodology and peak identification methodology used for identifying and quantifying each 92 pseudo-component as described in the Experiments section herein. Further, "total C_" weightpercent and mole percent values for the pseudo components were obtained using the pseudocomponent analysis methodology involving correlations developed by Katz and Firoozabadi(Katz, D.L., and A. Firoozabadi, 1978. Predicting phase behavior of condensate/crude-oilsystems using methane interaction coefficients, J. Petroleum Technology (Nov. 1978), 1649-1655) as described in the Experiments section, including the exemplary molar and weightpercentage determinations.

[0311] The use of "normal-C_" (e.g., normal-CIO) herein and in the claims is meant to referto the amount of a particular normal alkane hydrocarbon compound found in a condensablehydrocarbon fluid determined as described herein, particularly in the section labeled"Experiments" herein. That is "normal-C_" is determined from the GC peak areas determinedusing the whole oil gas chromatography (WOGC) analysis methodology according to theprocedure described in the Experiments section of this application. Further, "total C_" isdetermined from the whole oil gas chromatography (WOGC) peak identification and integrationmethodology used for identifying and quantifying individual compound peaks as described in theExperiments section herein. Further, "normal&amp;#1470;C_" weight percent and mole percent values forthe normal alkane compounds were obtained using methodology analogous to the pseudocomponent exemplary molar and weight percentage determinations explained in the Experimentssection, except that the densities and molecular weights for the particular normal alkanecompound of interest were used and then compared to the totals obtained in the pseudocomponent methodology to obtain weight and molar percentages.

[0312] The following discussion of Figure 16 concerns data obtained in Examples 1-5which are discussed in the section labeled "Experiments". The data was obtained through theexperimental procedures, gas sample collection procedures, hydrocarbon gas sample gaschromatography (GC) analysis methodology, and gas sample GC peak identification andintegration methodology discussed in the Experiments section. For clarity, when referring to gaschromatograms of gaseous hydrocarbon samples, graphical data is provided for one unstressedexperiment through Example 1, two 400 psi stressed experiments through Examples 2 and 3, andtwo 1,000 psi stressed experiments through Examples 4 and 5.

[0313] Figure 16 is a bar graph showing the concentration, in molar percentage, of thehydrocarbon species present in the gas samples taken from each of the three stress levels testedand analyzed in the laboratory experiments discussed herein. The gas compound molarpercentages were obtained through the experimental procedures, gas sample collection PCMJS2008/005008 93 WO 2008/143745 procedures, hydrocarbon gas sample gas chromatography (GC) analysis methodology, gassample GC peak integration methodology and molar concentration determination proceduresdescribed herein. For clarity, the hydrocarbon molar percentages are taken as a percentage of thetotal of all identified hydrocarbon gas GC areas (i.e., methane, ethane, propane, iso-butane, n-butane, iso-pentane, n-pentane, 2-methyl pentane, and n-hexane) and calculated molarconcentrations. Thus the graphed methane to normal C6 molar percentages for all of theexperiments do not include the molar contribution of any associated non-hydrocarbon gas phaseproduct (e.g., hydrogen, C02 or HfeS), any of the unidentified hydrocarbon gas species listed inTables 2,4, 5, 7, or 9 (e.g., peak numbers 2, 6, 8-11,13, 15-22, 24-26, and 28-78 in Table 2) orany of the gas species dissolved in the liquid phase which were separately treated in the liquidGC’s. The y-axis 3080 represents the concentration in terms of molar percent of each gaseouscompound in the gas phase. The x-axis 3081 contains the identity of each hydrocarboncompound from methane to normal hexane. The bars 3082A-I represent the molar percentage ofeach gaseous compound for the unstressed experiment of Example 1. That is 3082A representsmethane, 3082B represents ethane, 3082C represents propane, 3082D represents iso-butane,3082E represents normal butane, 3082F represents iso-pentane, 3082G represents normalpentane, 3082H represents 2-methyl pentane, and 30821 represents normal hexane. The bars3083A-I and 3084A-I represent the molar percent of each gaseous compound for samples fromthe duplicate 400 psi stressed experiments of Examples 2 and 3, with the letters assigned in themanner described for the unstressed experiment. While the bars 3085A-I and 3086A-I representthe molar percent of each gaseous compound for the duplicate 1,000 psi stressed experiments ofExamples 4 and 5, with the letters assigned in the manner described for the unstressedexperiment. From Figure 16 it can be seen that the hydrocarbon gas produced in all theexperiments is primarily methane, ethane and propane on a molar basis. It is further apparentthat the unstressed experiment, represented by bars 3082A-I, contains the most methane 3082Aand least propane 3082C, both as compared to the 400 psi stress experiments hydrocarbon gasesand the 1,000 psi stress experiments hydrocarbon gases. Looking now at bars 3083A-I and3084A-I, it is apparent that the intermediate level 400 psi stress experiments produced ahydrocarbon gas having methane 3083A and 3084A and propane 3083C and 3084Cconcentrations between the unstressed experiment represented by bars 3082A and 3082C and the1,000 psi stressed experiment represented by bars 3085A and 3085C and 3086A and 3086C.Lastly, it is apparent that the high level 1,000 psi stress experiments produced hydrocarbon gaseshaving the lowest methane 308SA and 3086A concentration and the highest propaneconcentrations 3085C and 3086C, as compared to both the unstressed experiments represented 94 by bars 3082A and 3082C and the 400 psi stressed experiment represented by bars 3083A and3084A and 3083C and 3084C. Thus pyrolyzing oil shale under increasing levels of lithostaticstress appears to produce hydrocarbon gases having decreasing concentrations of methane andincreasing concentrations of propane.

[0314] The hydrocarbon fluid produced from the organic-rich rock formation may includeboth a condensable hydrocarbon portion (e.g. liquid) and a non-condensable hydrocarbon portion(e.g. gas). In some embodiments the non-condensable hydrocarbon portion includes methaneand propane. In some embodiments the molar ratio of propane to methane in the non-condensable hydrocarbon portion is greater than 0.32. In alternative embodiments, the molarratio of propane to methane in the non-condensable hydrocarbon portion is greater than 0.34,0.36 or 0.38. As used herein "molar ratio of propane to methane" is the molar ratio that may bedetermined as described herein, particularly as described in the section labeled "Experiments"herein. That is "molar ratio of propane to methane" is determined using the hydrocarbon gassample gas chromatography (GC) analysis methodology, gas sample GC peak identification andintegration methodology and molar concentration determination procedures described in theExperiments section of this application.

[0315] In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluidincludes benzene. In some embodiments the condensable hydrocarbon portion has a benzenecontent between 0.1 and 0.8 weight percent. Alternatively, the condensable hydrocarbon portionmay have a benzene content between 0.15 and 0.6 weight percent, a benzene content between0.15 and 0.5, or a benzene content between 0.15 and 0.5.

[0316] In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluidincludes cyclohexane. In some embodiments the condensable hydrocarbon portion has acyclohexane content less than 0.8 weight percent. Alternatively, the condensable hydrocarbonportion may have a cyclohexane content less than 0.6 weight percent or less than 0.43 weightpercent. Alternatively, the condensable hydrocarbon portion may have a cyclohexane contentgreater than 0.1 weight percent or greater than 0.2 weight percent.

[0317] In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluidincludes methyl-cyclohexane. In some embodiments the condensable hydrocarbon portion has amethyl-cyclohexane content greater than 0.5 weight percent. Alternatively, the condensablehydrocarbon portion may have a methyl-cyclohexane content greater than 0.7 weight percent or 95 greater than 0.75 weight percent. Alternatively, the condensable hydrocarbon portion may have amethyl-cyclohexane content less than 1.2 or 1.0 weight percent.

[0318] The use of weight percentage contents of benzene, cyclohexane, and methyl-cyclohexane herein and in the claims is meant to refer to the amount of benzene, cyclohexane,and methyl-cyclohexane found in a condensable hydrocarbon fluid determined as describedherein, particularly as described in the section labeled "Experiments" herein. That is, respectivecompound weight percentages are determined from the whole oil gas chromatography (WOGC)analysis methodology and whole oil gas chromatography (WOGC) peak identification andintegration methodology discussed in the Experiments section herein. Further, the respectivecompound weight percentages were obtained as described for Figure 11, except that eachindividual respective compound peak area integration was used to determine each respectivecompound weight percentage. For clarity, the compound weight percentages are taken as apercentage of the entire C3 to pseudo C38 whole oil gas chromatography areas and calculatedweights as used in the pseudo compound data presented in Figure 7.

[0319] In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluidhas an API gravity greater than 30. Alternatively, the condensable hydrocarbon portion mayhave an API gravity greater than 30, 32, 34, 36, 40,42 or 44. As used herein and in the claims,API gravity may be determined by any generally accepted method for determining API gravity.

[0320] In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluidhas a basic nitrogen to total nitrogen ratio between 0.1 and 0.50. Alternatively, the condensablehydrocarbon portion may have a basic nitrogen to total nitrogen ratio between 0.15 and 0.40. Asused herein and in the claims, basic nitrogen and total nitrogen may be determined by anygenerally accepted method for determining basic nitrogen and total nitrogen. Where resultsconflict, the generally accepted more accurate methodology shall control.

[0321] The discovery that lithostatic stress can affect the composition of produced fluidsgenerated within an organic-rich rock via heating and pyrolysis implies that the composition ofthe produced hydrocarbon fluid can also be influenced by altering the lithostatic stress of theorganic-rich rock formation. For example, the lithostatic stress of the organic-rich rockformation may be altered by choice of pillar geometries and/or locations and/or by choice ofheating and pyrolysis formation region thickness and/or heating sequencing.

[0322] Pillars are regions within the organic-rich rock formation left unpyrolyzed at a giventime to lessen or mitigate surface subsidence. Pillars may be regions within a formation 96 surrounded by pyrolysis regions within the same formation. Alternatively, pillars may be part ofor connected to the unheated regions outside the general development area. Certain regions thatact as pillars early in the life of a producing field may be converted to producing regions later inthe life of the field.

[0323] Typically in its natural state, the weight of a formation’s overburden is fairlyuniformly distributed over the formation. In this state the lithostatic stress existing at particularpoint within a formation is largely controlled by the thickness and density of the overburden. Adesired lithostatic stress may be selected by analyzing overburden geology and choosing aposition with an appropriate depth and position.

[0324] Although lithostatic stresses are commonly assumed to be set by nature and notchangeable short of removing all or part of the overburden, lithostatic stress at a specific locationwithin a formation can be adjusted by redistributing the overburden weight so it is not uniformlysupported by the formation. For example, this redistribution of overburden weight may beaccomplished by two exemplary methods. One or both of these methods may be used within a.single formation. In certain cases, one method may be primarily used earlier in time whereas theother may be primarily used at a later time. Favorably altering the lithostatic stress experiencedby a formation region may be performed prior to instigating significant pyrolysis within theformation region and also before generating significant hydrocarbon fluids. Alternately,favorably altering the lithostatic stress may be performed simultaneously with the pyrolysis.

[0325] A first method of altering lithostatic stress involves making a region of a subsurfaceformation less stiff than its neighboring regions. Neighboring regions thus increasingly act aspillars supporting the overburden as a particular region becomes less stiff. These pillar regionsexperience increased lithostatic stress whereas the less stiff region experience reduced lithostaticstress. The amount of change in lithostatic stress depends upon a number of factors including,for example, the change in stiffness of the treated region, the size of the treated region, the pillarsize, the pillar spacing, the rock compressibility, and the rock strength. In an organic-rich rockformation, a region within a formation may be made to experience mechanical weakening bypyrolyzing the region and creating void space within the region by removing produced fluids. Inthis way a region within a formation may be made less stiff than neighboring regions that havenot experienced pyrolysis or have experienced a lesser degree of pyrolysis or production.

[0326] A second method of altering lithostatic stress involves causing a region of asubsurface formation to expand and push against the overburden with greater force than 97 neighboring regions. This expansion may remove a portion of the overburden weight from theneighboring regions thus increasing the lithostatic stress experienced by the heated region andreducing the lithostatic stress experienced by neighboring regions. If the expansion is sufficient,horizontal fractures will form in the neighboring regions and the contribution of these regions tosupporting the overburden will decrease. The amount of change in lithostatic stress dependsupon a number of factors including, for example, the amount of expansion in the treated region,the size of the treated region, the pillar size, the pillar spacing, the rock compressibility, and therock strength. A region within a formation may be made to expand by heating it so to causethermal expansion of the rock. Fluid expansion or fluid generation can also contribute toexpansion if the fluids are largely trapped within the region. The total expansion amount may beproportional to the thickness of the heated region. It is noted that if pyrolysis occurs in theheated region and sufficient fluids are removed, the heated region may mechanically weaken andthus may alter the lithostatic stresses experienced by the neighboring regions as described in thefirst exemplary method.

[0327] Embodiments of the method may include controlling the composition of producedhydrocarbon fluids generated by heating and pyrolysis from a first region within an organic-richrock formation by increasing the lithostatic stresses within the first region by first heating andpyrolyzing formation hydrocarbons present in the organic-rich rock formation and producingfluids from a second neighboring region within the organic-rich rock formation such that theYoung’s modulus (i.e., stiffness) of the second region is reduced.

[0328] Embodiments of the method may include controlling the composition of producedhydrocarbon fluids generated by heating and pyrolysis from a first region within an organic-richrock formation by increasing the lithostatic stresses within the first region by heating the firstregion prior to or to a greater degree than neighboring regions within the organic-rich rockformation such that the thermal expansion within the first region is greater than that within theneighboring regions of the organic-rich rock formation.

[0329] Embodiments of the method may include controlling the composition of producedhydrocarbon fluids generated by heating and pyrolysis from a first region within an organic-richrock formation by decreasing the lithostatic stresses within the first region by heating one ormore neighboring regions of the organic-rich rock formation prior to or to a greater degree thanthe first region such that the thermal expansion within the neighboring regions is greater than thatwithin the first region. > 98 [0330] Embodiments of the method may include locating, sizing, and/or timing the heating ofheated regions within an organic-rich rock formation so as to alter the in situ lithostatic stressesof current or future heating and pyrolysis regions within the organic-rich rock formation so as tocontrol the composition of produced hydrocarbon fluids.

[0331] Some production procedures include in situ heating of an organic-rich rock formationthat contains both formation hydrocarbons and formation water-soluble minerals prior tosubstantial removal of the formation water-soluble minerals from the organic-rich rockformation. In some embodiments of the invention there is no need to partially, substantially orcompletely remove the water-soluble minerals prior to in situ heating. For example, in an oilshale formation that contains naturally occurring nahcolite, the oil shale may be heated prior tosubstantial removal of the nahcolite by solution mining. Substantial removal of a water-solublemineral may represent the degree of removal of a water-soluble mineral that occurs from anycommercial solution mining operation as known in the art. Substantial removal of a water-soluble mineral may be approximated as removal of greater than 5 weight percent of the totalamount of a particular water-soluble mineral present in the zone targeted for hydrocarbon fluid:production in the organic-rich rock formation. In alternative embodiments, in situ heating of theorganic-rich rock formation to pyrolyze formation hydrocarbons may be commenced prior toremoval of greater than 3 weight percent, alternatively 7 weight percent, 10 weight percent or 13weight percent of the formation water-soluble minerals from the organic-rich rock formation.

[0332] The impact of heating oil shale to produce oil and gas prior to producing nahcolite isto convert the nahcolite to a more recoverable form (soda ash), and provide permeabilityfacilitating its subsequent recovery. Water-soluble mineral recovery may take place as soon asthe retorted oil is produced, or it may be left for a period of years for later recovery. If desired,the soda ash can be readily converted back to nahcolite on the surface. The ease with which thisconversion can be accomplished makes the two minerals effectively interchangeable.

[0333] In some production processes, heating the organic-rich rock formation includesgenerating soda ash by decomposition of nahcolite. The method may include processing anaqueous solution containing water-soluble minerals in a surface facility to remove a portion ofthe water-soluble minerals. The processing step may include removing the water-solubleminerals by precipitation caused by altering the temperature of the aqueous solution.

[0334] The water-soluble minerals may include sodium. The water-soluble minerals mayalso include nahcolite (sodium bicarbonate), soda ash (sodium carbonate), dawsonite 99 (NaAl(COj)(OH)2), or combinations thereof. The surface processing may further includeconverting the soda ash back to sodium bicarbonate (nahcolite) in the surface facility by reactionwith C02. After partial or complete removal of the water-soluble minerals, the aqueous solutionmay be re-injected into a subsurface formation where it may be sequestered. The subsurfaceformation may be the same as or different from the original organic-rich rock formation.

[0335] In some production processes, heating of the organic-rich rock formation bothpyrolyzes at least a portion of the formation hydrocarbons to create hydrocarbon fluids andmakes available migratory contaminant species previously bound in the organic-rich rockformation. The migratory contaminant species may be formed through pyrolysis of the formationhydrocarbons, may be liberated from the formation itself upon heating, or may be madeaccessible through the creation of increased permeability upon heating of the formation. Themigratory contaminant species may be soluble in water or other aqueous fluids present in orinjected into the organic-rich rock formation.

[0336] Producing hydrocarbons from pyrolyzed oil shale will generally leave behind somemigratory contaminant species which are at least partially water-soluble. Depending on thehydrological connectivity of the pyrolyzed shale oil to shallower zones, these components mayeventually migrate into ground water in concentrations which are environmentally unacceptable.The types of potential migratory contaminant species depend on the nature of the oil shalepyrolysis and the composition of the oil shale being converted. If the pyrolysis is performed inthe absence of oxygen or air, the contaminant species may include aromatic hydrocarbons (e.g.benzene, toluene, ethylbenzene, xylenes), polyaromatic hydrocarbons (e.g. anthracene, pyrene,naphthalene, chrysene), metal contaminants (e.g. As, Co, Pb, Mo, Ni, and Zn), and other speciessuch as sulfates, ammonia, Al, K, Mg, chlorides, fluorides and phenols. If oxygen or air isemployed, contaminant species may also include ketones, alcohols, and cyanides. Further, thespecific migratory contaminant species present may include any subset or combination of theabove-described species.

[0337] It may be desirable for a field developer to assess the connectivity of the organic-richrock formation to aquifers. This may be done to determine if, or to what extent, in situ pyrolysisof formation hydrocarbons in the organic-rich rock formation may create migratory species withthe propensity to migrate into an aquifer. If the organic-rich rock formation is hydrologicallyconnected to an aquifer, precautions may be taken to reduce or prevent species generated orliberated during pyrolysis from entering the aquifer. Alternatively, the organic-rich rockformation may be flushed with water or an aqueous fluid after pyrolysis as described herein to WO 2008/143745 PCMJS2008/005008 100 remove water-soluble minerals and/or migratory contaminant species. In other embodiments, theorganic-rich rock formation may be substantially hydrologically unconnected to any source ofground water. In such a case, flushing the organic-rich rock formation may not be desirable forremoval of migratory contaminant species but may nevertheless be desirable for recovery ofwater-soluble minerals.

[0338] Following production of hydrocarbons from an organic-rich formation, somemigratory contaminant species may remain in the rock formation. In such case, it may bedesirable to inject an aqueous fluid into the organic-rich rock formation and have the injectedaqueous fluid dissolve at least a portion of the water-soluble minerals and/or the migratorycontaminant species to form an aqueous solution. The aqueous solution may then be producedfrom the organic-rich rock formation through, for example, solution production wells. Theaqueous fluid may be adjusted to increase the solubility of the migratory contaminant speciesand/or the water-soluble minerals. The adjustment may include the addition of an acid or base toadjust the pH of the solution. The resulting aqueous solution may then be produced from theorganic-rich rock formation to the surface for processing.

[0339] After initial aqueous fluid production, it may further be desirable to flush the maturedorganic-rich rock zone and the unmatured organic-rich rock zone with an aqueous fluid. Theaqueous fluid may be used to further dissolve water-soluble minerals and migratory contaminantspecies. The flushing may optionally be completed after a substantial portion of the hydrocarbonfluids have been produced from the matured organic-rich rock zone. In some embodiments, theflushing step may be delayed after the hydrocarbon fluid production step. The flushing may bedelayed to allow heat generated from the heating step to migrate deeper into surroundingunmatured organic-rich rock zones to convert nahcolite within the surrounding unmaturedorganic-rich rock zones to soda ash. Alternatively, the flushing may be delayed to allow heatgenerated from the heating step to generate permeability within the surrounding unmaturedorganic-rich rock zones. Further, the flushing may be delayed based on current and/or forecastmarket prices of sodium bicarbonate, soda ash, or both as further discussed herein. This methodmay be combined with any of the other aspects of the invention as discussed herein [0340] Upon flushing of an aqueous solution, it may be desirable to process the aqueoussolution in a surface facility to remove at least some of the migratory contaminant species. Themigratory contaminant species may be removed through use of, for example, an adsorbentmaterial, reverse osmosis, chemical oxidation, bio-oxidation, and/or ion exchange. Examples of 101 these processes are individually known in the art. Exemplary adsorbent materials may includeactivated carbon, clay, or fuller’s earth.

[0341] In certain areas with oil shale resources, additional oil shale resources or otherhydrocarbon resources may exist at lower depths. Other hydrocarbon resources may includenatural gas in low permeability formations (so-called “tight gas”) or natural gas trapped in andadsorbed on coal (so called “coalbed methane”). In some embodiments with multiple oil shaleresources it may be advantageous to develop deeper zones first and then sequentially shallowerzones. In this way, wells need not cross hot zones or zones of weakened rock. In otherembodiments in may be advantageous to develop deeper zones by drilling wells through regionsbeing.utilized as pillars for shale oil development at a shallower depth.

[0342] Simultaneous development of shale oil resources and natural gas resources in thesame area can synergistically utilize certain facility and logistic operations. For example, gastreating may be performed at a single plant. Likewise personnel may be shared among thedevelopments.

[0343] Figure 6 illustrates a schematic diagram of an embodiment of surface facilities 70that may be configured to treat a produced fluid. The produced fluid 85 may be produced fromthe subsurface formation 84 though a production well 71 as described herein. The produced fluidmay include any of the produced fluids produced by any of the methods as described herein. Thesubsurface formation 84 may be any subsurface formation, including, for example, an organic·rich rock formation containing any of oil shale, coal, or tar sands for example. A productionscheme may involve quenching 72 produced fluids to a temperature below 300° F, 200° F, oreven 100° F, separating out condensable components (i.e., oil 74 and water 75) in an oil separator73, treating the noncondensable components 76 (i.e. gas) in a gas treating unit 77 to removewater 78 and sulfur species 79, removing the heavier components from the gas (e.g., propane andbutanes) in a gas plant 81 to form liquid petroleum gas (LPG) 80 for sale, and generatingelectrical power 82 in a power plant 88 from the remaining gas 83. The electrical power 82 maybe used as an energy source for heating the subsurface formation 84 through any of the methodsdescribed herein. For example, the electrical power 82 may be feed at a high voltage, forexample 132 kV, to a transformer 86 and let down to a lower voltage, for example 6600 V,before being fed to an electrical resistance heater element located in a heater well 87 located inthe subsurface formation 84. In this way all or a portion of the power required to heat thesubsurface formation 84 may be generated from the non-condensable portion of the producedfluids 85. Excess gas, if available, may be exported for sale. 102 [0344] Produced fluids from in situ oil shale production contain a number of componentswhich may be separated in surface facilities. The produced fluids typically contain water,noncondensable hydrocarbon alkane species (e.g., methane, ethane, propane, n&amp;#1470;butane,isobutane), noncondensable hydrocarbon alkene species (e.g., ethene, propene), condensablehydrocarbon species composed of (alkanes, olefins, aromatics, and polyaromatics among others),C02,C0,H2,H2S,andNH3.

[0345] In a surface facility, condensable components may be separated from non-condensable components by reducing temperature and/or increasing pressure. Temperaturereduction may be accomplished using heat exchangers cooled by ambient air or available water.Alternatively, the hot produced fluids may be cooled via heat exchange with producedhydrocarbon fluids previously cooled. The pressure may be increased via centrifugal orreciprocating compressors. Alternatively, or in conjunction, a diffuser-expander apparatus maybe used to condense out liquids from gaseous flows. Separations may involve several stages ofcooling and/or pressure changes.

[0346] Water in addition to condensable hydrocarbons may be dropped out of the gas whenreducing temperature or increasing pressure. Liquid water may be separated from condensablehydrocarbons via gravity settling vessels or centrifugal separators. Demulsifiers may be used toaid in water separation.

[0347] Methods to remove C02, as well as other so-called acid gases (such as H2S), fromproduced hydrocarbon gas include the use of chemical reaction processes and of physical solventprocesses. Chemical reaction processes typically involve contacting the gas stream with anaqueous amine solution at high pressure and/or low temperature. This causes the acid gas speciesto chemically react with the amines and go into solution. By raising the temperature and/orlowering the pressure, the chemical reaction can be reversed and a concentrated stream of acidgases can be recovered. An alternative chemical reaction process involves hot carbonatesolutions, typically potassium carbonate. The hot carbonate solution is regenerated and theconcentrated stream of acid gases is recovered by contacting the solution with steam. Physicalsolvent processes typically involve contacting the gas stream with a glycol at high pressureand/or low temperature. Like the amine processes, reducing the pressure or raising thetemperature allows regeneration of the solvent and recovery of the acid gases. Certain amines orglycols may be more or less selective in the types of acid gas species removed. Sizing of any ofthese processes requires determining the amount of chemical to circulate, the rate of circulation,the energy input for regeneration, and the size and type of gas-chemical contacting equipment.

Contacting equipment may include packed or multi-tray countercurrent towers. Optimal sizingfor each of these aspects is highly dependent on the rate at which gas is being produced from theformation and the concentration of the acid gases in the gas stream.

[0348] Acid gas removal may also be effectuated through the use of distillation towers. Such towers may include an intermediate freezing section wherein frozen C02 and H2S particles areallowed to form. A mixture of frozen particles and liquids fall downward into a stripping section,where the lighter hydrocarbon gasses break out and rise within the tower. A rectification sectionmay be provided at an upper end of the tower to further facilitate the cleaning of the overhead gasstream. · [0349] The hydrogen content of a gas stream may be adjusted by either removing all or aportion of the hydrogen or by removing all or a portion of the non-hydrogen species (e.g., C02,CH4, etc.) Separations may be accomplished using cryogenic condensation, pressure-swing ortemperature-swing adsorption, or selective diffusion membranes. If additional hydrogen· isneeded, hydrogen may be made by reforming methane via the classic water-shift reaction.

EXPERIMENTS

[0350] Heating experiments were conducted on several different oil shale specimens and theliquids and gases released from the heated oil shale examined in detail. An oil shale sample fromthe Mahogany formation in the Piceance Basin in Colorado was collected. A solid, continuousblock of the oil shale formation, approximately 1 cubic foot in size, was collected from the pilotmine at the Colony mine site on the eastern side of Parachute Creek. The oil shale block wasdesignated CM-1B. The core specimens taken from this block, as described in the followingexamples, were all taken from the same stratigraphic interval. The heating tests were conductedusing a Parr vessel, model number 243HC5, which is shown in Figure 18 and is available fromParr Instrument Company.

Example 1 [0351] Oil shale block CM-1B was cored across the bedding planes to produce a cylinder1.391 inches in diameter and approximately 2 inches long. A gold tube 7002 approximately 2inches in diameter and 5 inches long was crimped and a screen 7000 inserted to serve as asupport for the core specimen 7001 (Figure 17). The oil shale core specimen 7001, 82.46 gramsin weight, was placed on the screen 7000 in the gold tube 7002 and the entire assembly placedinto a Parr heating vessel. The Parr vessel 7010, shown in Figure 18, had an internal volume of565 milliliters. Argon was used to flush the Parr vessel 7010 several times to remove air present WO 2008/143745 in the chamber and the vessel pressurized to S00 psi with argon. The Parr vessel was then placedin a furnace which was designed to fit the Parr vessel. The furnace was initially at roomtemperature and was heated to 400 °C after the Parr vessel was placed in the furnace. Thetemperature of the Parr vessel achieved 400 °C after about 3 hours and remained in the 400 °C5 furnace for 24 hours. The Parr vessel was then removed from the furnace and allowed to cool toroom temperature over a period of approximately 16 hours.

[0352] The room temperature Parr vessel was sampled to obtain a representative portion ofthe gas remaining in the vessel following the heating experiment. A small gas sampling cylinderISO milliliters in volume was evacuated, attached to the Parr vessel and the pressure allowed to10 equilibrate. Gas chromatography (GC) analysis testing and non-hydrocarbon gas sample gaschromatography (GC) (GC not shown) of this gas sample yielded the results shown in Figure 19,Table 2 and Table 1. In Figure 19 the y-axis 4000 represents the detector response in pico-amperes (pA) while the x&amp;#1470;axis 4001 represents the retention time in minutes. In Figure 19 peak4002 represents the response for methane, peak 4003 represents the response for ethane, peak15 4004 represents the response for propane, peak 4005 represents the response for butane, peak 4006 represents the response for pentane and peak 4007 represents the response for hexane.From the GC results and the known volumes and pressures involved the total hydrocarboncontent of the gas (2.09 grams), C02 content of the gas (3.35 grams), and H2S content of the gas(0.06 gram) were obtained. 105

Table 2

Peak and Area Details for Fig. 19 - Example 1-0 stress - Gas GC

Peak Number Ret Time[min] Area [pA*s] Compound Name 1 0.910 1.46868e4 Methane 2 0.999 148.12119 ? 3 1.077 1.26473e4 Ethane 4 2.528 1.29459e4 Propane 5 4.243 2162.93066 iC4 6 4.922 563.11804 ? 7 5.022 5090.54150 n-Butane 8 5.301 437.92255 7 9 5.446 4.67394 ? 10 5.582 283.92194 ? 11 6.135 15.47334 ? 12 6.375 1159.83130 iC5 13 6.742 114.83960 ? 14 6.899 1922.98450 n-Pentane 15 7.023 2.44915 ? 16 7.136 264.34424 ? . 17. 7.296 127.60601 ? 18 7.383 118.79453 ? 19 7.603 3.99227 ? 20 8.138 13.15432 7 21 8.223 13.01887 ? 22 8.345 103.15615 ? 23 8.495 291.26767 2-methyl 24 8.651 15.64066 pentane 25 8.884 91.85989 ? 26 9.165 40.09448 7 27 9.444 534.44507 ? 28 9.557 2.64731 n-Hexane 29 9.650 32.28295 ? 30 9.714 52.42796 ? 31 9.793 42.05001 ? 32 9.852 8.93775 7 33 9.914 4.43648 7 34 10.013 24.74299 ? 35 10.229 13.34387 ? 36 10.302 133.95892 7 37 10.577 2.67224 7 38 11.252 27.57400 ? 39 11.490 23.41665 ? 40 11.567 8.13992 7 41 11.820 32.80781 ? 42 11.945 4.61821 ? 43 12.107 30.67044 ? 44 12.178 2.58269 ? 45 12.308 13.57769 ?

Table 2. (Cont.)

Peak Number Ret Time[mini Area [pA*s] Compound Name 46 12.403 12.43018 7 47 12.492 34.29918 ? 48 12.685 4.71311 ? 49 12.937 183.31729 ? 50 13.071 7.18510 ? 51 13.155 2.01699 ? 52 13.204 7.77467 7 53 13.317 7.21400 ? 54 13.443 4.22721 ? 55 13.525 35.08374 ? 56 13.903 18.48654 ? .57 14.095 6.39745 ? 58 14.322 3.19935 ? 59 14.553 8.48772 ? 60 14.613 3.34738 ? 61 14.730 5.44062 ? 62 14.874 40.17010 7 63 14.955 3.41596 7 64 15.082 3.04766 ? 65 15.138 7.33028 ? 66 15.428 2.71734 ? 67 15.518 11.00256 7 68 15.644 5.16752 7 69 15.778 45.12025 7 70 15.855 3.26920 7 71 16.018 3.77424 ? 72 16.484 4.66657 ? 73 16.559 5.54783 7 74 16.643 10.57255 7 75 17.261 2.19534 ? 76 17.439 10.26123 7 77 17.971 1.85618 7 78 18.097 11.42077 7 [0353] TKe Parr vessel was then vented to achieve atmospheric pressure, the vessel opened,and liquids collected from both inside the gold tube and in the bottom of the Parr vessel. Water5 was separated from the hydrocarbon layer and weighed. The amount collected is noted in Table1. The collected hydrocarbon liquids were placed in a small vial, sealed and stored in theabsence of light. No solids were observed on the walls of the gold tube or the walls of the Parrvessel. The solid core specimen was weighed and determined to have lost 19.21grams as a resultof heating. Whole oil gas chromatography (WOGC) testing of the liquid yielded the results10 shown in Figure 20, Table 3, and Table 1. In Figure 20 the y-axis 5000 represents the detectorresponse in pico-amperes (pA) while the x-axis 5001 represents the retention time in minutes.The GC chromatogram is shown generally by label 5002 with individual identified peaks labeledwith abbreviations.

Table 3

Peak and Area Details for Fig. 20 - Example 1-0 stress - Liquid GC

Peak Ret Time Peak Area Compound Number [min] [pA*s] Name 1 2.660 119.95327 iC4 2 2.819 803.25989 nC4 3 3.433 1091.80298 iC5 4 3.788 2799.32520 nC5 5 5.363 1332.67871 2-methyl pentane (2MP) 6 5.798 466.35703 3-methyl pentane (3MP) 7 6.413 3666.46240 nC6 8 7.314 1161.70435 Methyl cyclopentane (MCP) 9 8.577 287.05969 Benzene (BZ) 10 9.072 530.19781 Cyclohexane (CH) 11 10.488 4700.48291 nC7 12 11.174 937.38757 Methyl cyclohexane (MCH) 13 12.616 882.17358 Toluene (TOL) 14 14.621 3954.29687 nC8 15 18.379 3544.52905 nC9 16 21.793 3452.04199 nCIO 17 24.929 3179.11841 nCll 18 27.843 2680.95459 nC12 19 30.571 2238.89600 nC13 20 33.138 2122.53540 nC14 21 35.561 1773.59973 nC15 22 37.852 1792.89526 nC16 23 40.027 1394.61707 nC17 24 40.252 116.81663 Pristane (Pr) 25 42.099 1368.02734 nC18 26 42.322 146.96437 Phytane (Ph) 27 44.071 1130.63342 nC19 28 45.956 920.52136 nC20 29 47.759 819.92810 nC21 30 49.483 635.42065 nC22 31 51.141 563.24316 nC23 32 52.731 432.74606 nC24 33 54.261 397.36270 nC25 34 55.738 307.56073 nC26 35 57.161 298.70926 nC27 36 58.536 252.60083 nC28 37 59.867 221.84540 nC29 38 61.154 190.29596 nC30 39 62.539 123.65781 nC31 40 64.133 72.47668 nC32 41 66.003 76.84142 nC33 42 68.208 84.35004 nC34 43 70.847 36.68131 nC35 44 74.567 87.62341 nC36 45 77.798 33.30892 nC37 46 82.361 21.99784 nC38 Totals : 5.32519e4

Example 2 [0354] Oil shale block CM-1B was cored in a manner similar to that of Example 1 exceptthat a 1 inch diameter core was created. With reference to Figure 21, the core specimen 7050was approximately 2 inches in length and weighed 42.47 grams. This core specimen 7050 wasplaced in a Berea sandstone cylinder 7051 with a 1-inch inner diameter and a 1.39 inch outerdiameter. Berea plugs 7052 and 7053 were placed at each end of this assembly, so that the corespecimen was completely surrounded by Berea. The Berea cylinder 7051 along with the corespecimen 7050 and the Berea end plugs 7052 and 7053 were placed in a slotted stainless steelsleeve and clamped into place. The sample assembly 7060 was placed in a spring-loaded mini-load-frame 7061 as shown in Figure 22. Load was applied by tightening the nuts 7062 and 7063at the top of the load frame 7061 to compress the springs 7064 and 7065. The springs 7064 and7065 were high temperature, Inconel springs, which delivered 400 psi effective stress to the oilshale specimen 7060 when compressed. Sufficient travel of the springs 7064 and 7065 remainedin order to accommodate any expansion of the core specimen 7060 during the course of heating.In order to ensure that this was the case, gold foil 7066 was placed on one of the legs of theapparatus to gauge the extent of travel. The entire spring loaded apparatus 7061 was placed inthe Parr vessel (Figure 18) and the heating experiment conducted as described in Example 1.

[0355] As described in Example 1, the room temperature Parr vessel was then sampled toobtain a representative portion of the gas remaining in the vessel following the heatingexperiment. Gas sampling, hydrocarbon gas sample gas chromatography (GC) testing, and non-hydrocarbon gas sample gas. chromatography (GC) was conducted as in Example 1. Results areshown in Figure 23, Table 4 and Table 1. In Figure 23 the y-axis 4010 represents the detectorresponse in pico-amperes (pA) while the x-axis 4011 represents the retention time in minutes. InFigure 23 peak 4012 represents the response for methane, peak 4013 represents the response forethane, peak 4014 represents the response for propane, peak 4015 represents the response forbutane, peak 4016 represents the response for pentane and peak 4017 represents the response forhexane. From the gas chromatographic results and the known volumes and pressures involvedthe total hydrocarbon content of the gas was determined to be 1.33 grams and C02 content of thegas was 1.70 grams. 109

Table 4

Peak and Area Details for Fig. 23 - Example 2 - 400 psi stress - Gas GC

Peak Number Ret. Time[min] Areax [pA*s] Compound Name 1 0.910 1.36178e4 Methane 2 0.999 309.65613 ? 3 1.077 1:24143e4 Ethane 4 2.528 1.41685e4 Propane 5 4.240 2103.01929 iC4 6 4.917 1035.25513 7 7 5.022 5689.08887 n-Butane 8 5.298 450.26572 ? 9 5.578 302.56229 7 10 6.125 33.82201 ? 11 6.372 1136.37097 iC5 12 6.736 263.35754 ? 13 6.898 2254.86621 n-Pentane 14 7.066 7.12101 ? 15 7.133 258.31876 ? 16 7.293 126.54671 7 17 7.378 155.60977 ? 18 7.598 6.73467 ? 19 7.758 679.95312 7 20 8.133 27.13466 ? 21 8.216 24.77329 ? 22 8.339 124.70064 ? 23 8.489 289.12952 2-methyl pentane 24 8.644 19.83309 ? 25 8.878 92.18938 ? 26 9.184 102.25701 ? 27 9.438 664.42584 n-Hexane 28 9.549 2.91525 ? 29 9.642 26.86672 ? 30 9.705 49.83235 7 31 9.784 52.11239 ? 32 9.843 9.03158 ? 33 9.904 6.18217 7 34 10.004 24.84150 ? 35 10.219 13.21182 ? 36 10.292 158.67511 ? 37 10.411 2.49094 ? 38 10.566 3.25252 ? 39 11.240 46.79988 ? 40 11.478 29.59438 ? 41 11.555 12.84377 7 42 11.809 38.67433 7 43 11.935 5.68525 7 44 12.096 31.29068 7 45 12.167 5.84513 ? 46 12.297 15.52042 7 47 12.393 13.54158 7 48 12.483 30.95983 7 49 12.669 20.21915 7 50 12.929 229.00655 ? 51 13.063 6.38678 ? 52 13.196 10.89876 ? 47 13.306 7.91553 ? 48 13.435 5.05444 7 49 13.516 44.42806 ?

Table 4. (Cont.)

Peak Number Ret Time[min] Area fpA*s] Compound Name 50 13.894 20.61910 7 51 14.086 8.32365 ? 52 14.313 2.80677 ? 53 14.545 9.18198 ? 54 14.605 4.93703 &amp;#1491; 55 14.722 5.06628 7 56 14.865 46.53282 7 57 14.946 6.55945 ? 58 15.010 2.85594 ? 59 15.075 4.05371 ? 60 15.131 9.15954 ? 61 15.331 2.16523 ? 62 15.421 3.03294 ? 63 15.511 9.73797 7 64 15.562 5.22962 &amp;#1491; . 65 15.636 3.73105 ? 66 15.771 54.64651 7 67 15.848 3.95764 7 68 16.010 3.39639 7 69 16.477 5.49586 ? 70 16.552 6.21470 ? 71 16.635 11.08140 7 72 17.257 2.28673 7 73 17.318 2.82284 ? 74 17.433 11.11376 ? 75 17.966 2.54065 ? 76 18.090 14.28333 ? 77 78 79 80 81 82 [0356] At this point, the Parr vessel was vented to achieve atmospheric pressure, the vesselopened, and liquids collected from inside the Parr vessel. Water was separated from the5 hydrocarbon layer and weighed. The amount collected is noted in Table 1. The collectedhydrocarbon liquids were placed in a small vial, sealed and stored in the absence of light. Anyadditional liquid coating the surface of the apparatus or sides of the Parr vessel was collectedwith a paper towel and the weight of this collected liquid added to the total liquid collected. Anyliquid remaining in the Berea sandstone was extracted with methylene chloride and the weight10 accounted for in the liquid total reported in Table 1. The Berea sandstone cylinder and end capswere clearly blackened with organic material as a result of the heating. The organic material inthe Berea was not extractable with either toluene or methylene chloride, and was thereforedetermined to be coke formed from the cracking of hydrocarbon liquids. After the heatingexperiment, the Berea was crushed and its total organic carbon (TOC) was measured. This15 measurement was used to estimate the amount of coke in the Berea and subsequently how much 111 liquid must have cracked in the Berea. A constant factor of 2.283 was used to convert the TOCmeasured to an estimate of the amount of liquid, which must have been present to produce thecarbon found in the Berea. This liquid estimated is the “inferred oil” value shown in Table 1.The solid core specimen was weighed and determined to have lost 10.29 grams as a result of5 heating.

Example 3 [0357] Conducted in a manner similar to that of Example 2 on a core specimen from oil shaleblock CM-1B, where the effective stress applied was 400 psi. Results for the gas samplecollected and analyzed by hydrocarbon gas sample gas chromatography (GC) and non-10 hydrocarbon gas sample gas chromatography (GC) (GC not shown) are shown in Figure 24,Table 5 and Table 1. In Figure 24 the y-axis 4020 represents the detector response in pico-amperes (pA) while the x-axis 4021 represents the retention time in minutes. In Figure 24 peak4022 represents the response for methane, peak 4023 represents the response for ethane, peak4024 represents the response for propane, peak 4025 represents the response for butane, peak15 4026 represents the response for pentane and peak 4027 represents the response for hexane.

Results for the liquid collected and analyzed by whole oil gas chromatography (WOGC) analysisare shown in Figure 25, Table 6 and Table 1. In Figure 25 the y-axis 5050 represents thedetector response in pico-amperes (pA) while the x-axis 5051 represents the retention time inminutes. The GC chromatogram is shown generally by label 5052 with individual identified20 peaks labeled with abbreviations.

Table5

Peak and Area Details for Fig. 24 - Example 3 - 400 psi stress - Gas GC

Peak Number Ret TimeΓη&amp;#944;η&amp;#912; Area fpA*s] Compound Name 1 0.910 1.71356e4 Methane 2 0.998 341.71646 ? 3 1.076 1.52621e4 Ethane 4 2.534 1.72319e4 Propane 5 4.242 2564.04077 iC4 6 4.919 1066.90942 ? 7 5.026 6553.25244 n-Butane 8 5.299 467.88803 7 9 5.579 311.65158 ? 10 6.126 33.61063 ? 11 6.374 1280.77869 iC5 12 6.737 250.05510 &amp;#1491; 13 6.900 2412.40918 n-Pentane 14 7.134 249.80679 ? 15 7.294 122.60424 7 16 7.379 154.40988 ? 17 7.599 6.87471 ?

Table 5 (Cont.)

Peak Number Ret Time[mini Area [pA*s] Compound Name 18 8.132 25.50270 ? 19 8.216 22.33015 ? 20 8.339 129.17023 ? 21 8.490 304.97903 2-methyl pentane 22 8.645 18.48411 ? 23 8.879 98.23043 ? 24 9.187 89.71329 7 25 9.440 656.02161 n&amp;#1470;Hexane 26 9.551 3.05892 ? 27 9.645 25.34058 ? 28 9.708 45.14915 ? 29 9.786 48.62077 ? 30 9.845 10.03335 ? 31 9.906 5.43165 ? 32 10.007 22.33582 7 33. 10.219 16.02756 ? 34 10.295 196.43715 ? 35 10.413 2.98115 7 36 10.569 3.88067 ? 37 11.243 41.63386 ? 38 11.482 28.44063 &amp;#1500; 39 11.558 12.05196 ? 40 11.812 37.83630 7 41 11.938 5.45990 ? 42 12.100 31.03111 ? 43 12.170 4.91053 ? 44 12.301 15.75041 7 45 12.397 13.75454 ? 46 12.486 1.62203 7 47 12.672 7.97665 7 48 12.931 7.49605 ? 49 13.064 4.64921 7 50 13.103 41.82572 ? 51 13.149 19.01739 ? 52 13.198 7.34498 7 53 13.310 2.68912 ? 54 13.437 8.29593 7 55 13.519 3.93147 ? 56 13.898 4.75483 7 57 14.089 40.93447 ? 58 14.316 5.30140 7 59 14.548 5.79979 7 60 14.608 7.95179 7 61 14.725 1.91589 ? 62 14.869 2.75893 7 63 14.949 8.64343 ? 64 15.078 3.76481 ? 65 15.134 3.41854 7 66 15.335 45.59035 7 67 15.423 3.73501 7 68 15.515 5.84199 7 69 15.565 4.87036 ? 70 15.639 5.12607 ? 71 15.774 9.97469 ? 72 15.850 8.00434 ? 73 16.014 3.86749 7 74 16.480 9.71661 7

TableS. (Cont.)

Peak Number Ret Timefmin] Area [pA*s] Name 75 16.555 30.26099 ? 76 16.639 15.14775 ? 77 17.436 207.50433 ? 78 17.969 3.35393 ? 79 18.093 3.04880 ?

Table 6

Peak and Area Details from Fig. 25 - Example 3 - 400 psi stress - Liquid GC.

Peak Ret Time Peak Area Compound Number [min] [pA*s] Name 1 2.744 102.90978 iC4 2 2.907 817.57861 nC4 . 3 3.538 1187.01831 iC5 4 3.903 3752.84326 nC5 5 5.512 1866.25342 2MP 6 5.950 692.18964 3MP 7 6.580 6646.48242 nC6 8 7.475 2117.66919 MCP 9 8.739 603.21204 BZ 10 9.230 1049.96240 CH 11 10.668 9354.29590 nC7 12 11.340 2059.10303 MCH 13 12.669 689.82861 TOL 14 14.788 8378.59375 nC8 15 18.534 7974.54883 nC9 16 21.938 7276.47705 nCIO 17 25.063 6486.47998 nCll 18 27.970 5279.17187 nC12 19 30.690 4451.49902 nC13 20 33.254 4156.73389 nC14 21 35.672 3345.80273 nC15 22 37.959 3219.63745 nC16 23 40.137 2708.28003 nC17 24, 40.227 219.38252 Pr 25 42.203 2413.01929 nC18 26 42.455 317.17825 Ph . 27 44.173 2206.65405 nC19 28 46.056 1646.56616 nC20 29 47.858 1504.49097 nC21 30 49.579 1069.23608 nC22 31 51.234 949.49316 nC23 32 52.823 719.34735 nC24 33 54.355 627.46436 nC25 34 55.829 483.81885 nC26 35 57.253 407.86371 nC27 36 58.628 358.52216 nC28 37 59.956 341.01791 nC29 38 61.245 214.87863 nC30 39 62.647 146.06461 nC31 40 64.259 127.66831 nC32

Table 6 (Cont.)

Peak Number Ret Time[min] Peak Area[pA*s] Compound Name 41 66.155 85.17574 nC33 42 68.403 64.29253 nC34 43 71.066 56.55088 nC35 44 74.282 28.61854 nC36 45 78.140 220.95929 nC37 46 83.075 26.95426 nC38 Totals : 9.84518e4

Example 4 5 [0358] Conducted in a manner similar to that of Example 2 on a core specimen from oil shale block CM-1B; however, in this example the applied effective stress was 1,000 psi. Results forthe gas collected and analyzed by hydrocarbon gas sample gas chromatography (GC) and non-hydrocarbon gas sample gas chromatography (GC) (GC not shown) are shown in Figure 26,Table 7 and Table 1. In Figure 26 the y-axis 4030 represents the detector response in pico-10 amperes (pA) while the x-axis 4031 represents the retention time in minutes. In Figure 26· peak4032 represents the response for methane, peak 4033 represents the response for ethane, peak4034 represents the response for propane, peak 4035 represents the response for butane, peak4036 represents the response for pentane and peak 4037 represents the response for hexane.Results for the liquid collected and analyzed by whole oil gas chromatography (WOGC) are15 shown in Figure 27, Table 8 and Table 1. In Figure 27 the y-axis 6000 represents the detectorresponse in pico-amperes (pA) while the x-axis 6001 represents the retention time in minutes.The GC chromatogram is shown generally by label 6002 with individual identified peaks labeledwith abbreviations. 115

Table 7

Peak and Area Details for Fig. 26 - Example 4 -1000 psi stress - Gas GC

Peak Number Ret Time[min] Area [pA*s] Compound Name 1 0.910 1.43817e4 Methane 2 1.000 301.69287 ? 3 1.078 1.37821e4 Ethane 4 2.541 1.64047e4 Propane 5 4.249 2286.08032 iC4 6 4.924 992.04395 ? 7 5.030 6167.50000 n-Butane 8 5.303 534.37000 7 9 5.583 358.96567 7 10 6.131 27.44937 7 11 6.376 1174.68872 iC5 12 6.740 223.61662 ? 13 6.902 2340.79248 n-Pentane 14 7.071 5.29245 7 15 7.136 309.94775 7 16 7.295 154.59171 7 17 7.381 169.53279 7 18 7.555 2.80458 ? 19 7.601 5.22327 ? 20 7.751 117.69164 ? 21 8.134 29.41086 7 22 8.219 19.39338 7 23 8.342 133.52739 7 24 8.492 281.61343 2-methyl pentane 25 8.647 22.19704 7 26 8.882 99.56919 ? 27 9.190 86.65676 7 28 9.443 657.28754 n-Hexane 29 9.552 4.12572 7 30 9.646 34.33701 ? 31 9.710 59.12064 7 32 9.788 62.97972 7 33 9.847 15.13559 ? 34 9.909 6.88310 ? 35 10.009 29.11555 7 36 10.223 23.65434 ? 37 10.298 173.95422 ? 38 10.416 3.37255 7 39 10.569 7.64592 7 40 11.246 47.30062 7 41 11.485 32.04262 9 42 11.560 13.74583 7 43 11.702 2.68917 ? 44 11.815 36.51670 ? 45 11.941 6.45255 7 46 12.103 28.44484 ? 47 12.172 5.96475 7 48 12.304 17.59856 ? 49 12.399 15.17446 7 50 12.490 31.96492 7 51 12.584 3.27834 ? 52 12.675 14.08259 ? 53 12.934 207.21574 ? 54 13.105 8.29743 7

Table 7 (Cont.)

Peak Number Ret TimeΓπι&amp;#970;η] Area [pA*s] Compound Name 55 13.151 2.25476 ? 56 13.201 8.36965 ? 57 13.312 9.49917 ? 58 13.436 6.09893 ? 59 13.521 46.34579 ? 60 13.900 20.53506 ? 61 14.090 8.41120 ? 62 14.318 4.36870 7 63 14.550 8.68951 ? 64 14.610 4.39150 ? 65 14.727 4.35713 ? 66 14.870 37.17881 ? 67 14.951 5.78219 ? 68 15.080 5.54470 ? 69 15.136 8.07308 ? 70 15.336 2.07075 7 71 15.425 2.67118 ? 72 15.516 8.47004 ? 73 15.569 3.89987 ? 74 15.641 3.96979 7 75 15.776 40.75155 ? 76 16.558 5.06379 ? 77 16.641 8.43767 ? 78 17.437 6.00180 ? 79 18.095 7.66881 ? 80 15.853 3.97375 ? 81 16.016 5.68997 ? 82 16.482 3.27234 ? 5 117

Table 8

Peak and Area Details from Fig. 27 - Example 4 1000 &amp;#1470; psi stress - Liquid GC.

Peak Ret Time Peak Area Compound Number [min] [pA*s] Name 1 2.737 117.78948 iC4 2 2.901 923.40125 nC4 3 3.528 1079.83325 iC5 4 3.891 3341.44604 nC5 5 5.493 1364.53186 2MP 6 5.930 533.68530 3MP 7 6.552 5160.12207 nC6 8 7.452 1770.29932 MCP 9 8.717 487.04718 BZ 10 9.206 712.61566 CH 11 10.634 7302.51123 nC7 12 11. 1755.92236 MCH 13 12.760 2145.57666 TOL 14 14.755 6434.40430 nC8 15 18.503 6007.12891 nC9 16 21.906 5417.67480 nCIO 17 25.030 4565.11084 nCll 18 27.936 3773.91943 nC12 19 30.656 3112.23950 nC13 20 33.220 2998.37720 nC14 21 35.639 2304.97632 nC15 22 37.927 2197.88892 nC16 23 40.102 1791.11877 nC17 24 40.257 278.39423 Pr 25 42.171 1589.64233 0C18 26 42.428 241.65131 Ph 27 44.141 1442.51843 nC19 28 46.025 1031.68481 nC20 29 47.825 957.65479 nC21 30 49.551 609.59943 nC22 31 51.208 526.53339 nC23 32 52.798 383.01022 nC24 33 54.329 325.93640 nC25 34 55.806 248.12935 nC26 35 57.230 203.21725 nC27 36 58.603 168.78055 nC28 37 59.934 140.40034 nC29 38 61.222 95.47594 nC30 39 62.622 77.49546 nC31 40 64.234 49.08135 nC32 41 66.114 33.61663 nC33 42 68.350 27.46170 nC34 43 71.030 35.89277 nC35 44 74.162 16.87499 nC36 45 78.055 29.21477 nC37 46 82.653 9.88631 nC38 Totals: 7.38198e4 [0359] Conducted in a manner similar to that of Example 2 on a core specimen from oil shaleblock CM-1B; however, in this example the applied effective stress was 1,000 psi. Results forthe gas collected and analyzed by hydrocarbon gas sample gas chromatography (GC) and non-5 hydrocarbon gas sample gas chromatography (GC) (GC not shown) are shown in Figure 28,Table 9 and Table 1. In Figure 28 the y-axis 4040 represents the detector response in pico-amperes (pA) while the x-axis 4041 represents the retention time in minutes. In Figure 28 peak4042 represents the response for methane, peak 4043 represents the response for ethane, peak4044 represents the response for propane, peak 4045 represents the response for butane, peak10 4046 represents the response for pentane and peak 4047 represents the response for hexane.

Table 9

Peak and Area Details for Fig. 28 - Example 5 -1000 psi stress - Gas GC

Peak Number Ret Time[mini Area fpA*sl Compound Name 1 0.910 1.59035e4 Methane 2 0.999 434.21375 ? 3 1.077 1.53391e4 Ethane 4 2.537 1.86530e4 Propane 5 4.235 2545.45850 iC4 6 . 4.907 1192.68970 &amp;#1491; 7 5.015 6814.44678 n-Butane 8 5.285 687.83679 ? 9 5.564 463.25885 ? 10 6.106 30.02624 ? 11 6.351 1295.13477 iC5 12 6.712 245.26985 ? 13 6.876 2561.11792 n-Pentane 14 7.039 4.50998 ? 15 7.109 408.32999 ? 16 7.268 204.45311 ? 17 · 7.354 207.92183 ? 18 7.527 4.02397 ? 19 7.574 5.65699 ? 20 7.755 2.35952 ? 21 7.818 2.00382 ? 22 8.107 38.23093 ? 23 8.193 20.54333 ? 24 8.317 !48.54445 ? 25 8.468 300.31586 2-methyl pentane 26 8.622 26.06131 ? 27 8.858 113.70123 7 28 9.168 90.37163 ? 29 9.422 694.74438 n-Hexane 30 9.531 4.88323 ? 31 9.625 45.91505 ? 32 9.689 76.32931 ? 33 9.767 77.63214 ? 34 9.826 19.23768 ? 119

Table 9 (Cont.)

Peak Number Ret. Time[min] Area [pA*s] Name 35 9.889 8.54605 ? 36 9.989 37.74959 ? 37 10.204 30.83943 ? 38 10.280 184.58420 ? 39 10.397 4.43609 7 40 10.551 10.59880 ? 41 10.843 2.30370 7 42 11.231 55.64666 ? 43 11.472 35.46931 ? 44 11.547 17.16440 7 45 11.691 3.30460 7 46 . 11.804 39.46368 ? 47 11.931 7.32969 7 48 12.094 30.59748 ? 49 12.163 6.93754 7 50 12.295 18.69523 &amp;#1500; 51 12.391 15.96837 ? 52 12.482 33.66422 7 53 12.577 2.02121 ? 54 12.618 2.32440 ? 55 12.670 12.83803 ? 56 12.851 2.22731 7 57 12.929 218.23195 7 58 13.100 14.33166 ? 59 13.198 10.20244 ? 60 13.310 12.02551 ? 61 13.432 8.23884 7 62 13.519 47.64641 7 63 13.898 22.63760 ? 64 14.090 9.29738 7 65 14.319 3.88012 7 66 14.551 9.26884 7 67 14.612 4.34914 7 68 14.729 4.07543 7 69 14.872 46.24465 7 70 14.954 6.62461 ? 71 15.084 3.92423 ? 72 15.139 8.60328 7 73 15.340 2.17899 ? 74 15.430 2.96646 7 75 15.521 9.66407 ? 76 15.578 4.27190 ? 77 15.645 4.37904 ? 78 15.703 2.68909 ? 79 15.782 46.97895 ? 80 15.859 4.69475 ? 81 16.022 7.36509 7 82 16.489 3.91073 7 83 16.564 6.22445 ? 84 16.648 10.24660 7 85 17.269 2.69753 7 86 17.445 10.16989 7 87 17.925 2.28341 ? 88 17.979 2.71101 7 89 18.104 11.19730 7 PCT/U S2008/005008 120

Table 1

Summary data for Examples 1-5.

Example 1 Example 2 Example 3 Example 4 Example 5 Effective Stress (psi) 0 400 400 1000 1000 Sample weight (g) 82.46 42.57 48.34 43.61 43.73 Sample weight loss (g) 19.21 10.29 11.41 • 10.20 9.17 Fluids Recovered: Oil (g) 10.91 36.2 gal/lon 3.63 23.4 gal/ton 3.77 21.0 gal/ton 3.02 19.3 gal/ton 2.10 13/1 gal/ton Water (g) 0.90 2.6 gal/ton 0.30 1.7 gal/ton 034 1.7 gal/ton 0.39 2.1 gal/ton 0.28 1.5 gal/ton HC gas (g) 2.09 683 scf/ton 1.33 811 scf/ton 1.58 862 scf/ton 1.53 905 scf/ton 1.66 974 scf/ton COj(g) 3.35 700 scf/ton 1.70 690 scf/ton 1.64 586 scf/ton 1.74 690 scf/ton 1.71 673 scf/ton HjS (g) 0.06 0.0 0.0 0.0 0.0 Coke Recovered: 0.0 0.73 0.79 .47 0.53 Inferred Oil (g) 0.0 0 gal/ton 1.67 10.8 gal/ton 1.81 10.0 gal/ton 1.07 6.8 gal/ton 1.21 7.6 gal/ton Total Oil (g) 10.91 36.2 gal/ton 5.31 34.1 gal/ton 5.58 31.0 gal/ton 4.09 26.1 gal/ton 3.30 20.7 gal/ton Balance (g) 1.91 2.59 3.29 3.05 2.91 5

Analysis [0360] The gas and liquid samples obtained through the experimental procedures and gas andliquid sample collection procedures described for Examples 1-5, were analyzed by the followinghydrocarbon gas sample gas chromatography (GC) analysis methodology, non-hydrocarbon gas 10 sample gas chromatography (GC) analysis methodology, gas sample GC peak identification andintegration methodology, whole oil gas chromatography (WOGC) analysis methodology, andwhole oil gas chromatography (WOGC) peak identification and integration methodology.

[0361] Gas samples collected during the heating tests as described in Examples 1-5 wereanalyzed for both hydrocarbon and non-hydrocarbon gases, using an Agilent Model 6890 Gas 15 Chromatograph coupled to an Agilent Model 5973 quadrapole mass selective detector. The 6890GC was configured with two inlets (front and back) and two detectors (front and back) with twofixed volume sample loops for sample introduction. Peak identifications and integrations wereperformed using the Chemstation software (Revision A.03.01) supplied with the GC instrument.For hydrocarbon gases, the GC configuration consisted of the following: 20 a) split/splitless inlet (back position of the GC)

b) FED (Flame ionization detector) back position of the GC

121 c) HP Ultra-2 (5% Phenyl Methyl Siloxane) capillary columns (two) (25 meters x 200μπ1 ID) one directed to the FID detector, the other to an Agilent 5973 MassSelective Detector d) 500μ1 fixed volume sample loop 5 e) six-port gas sampling valve 0 cryogenic (liquid nitrogen) oven cooling capability g) Oven program -80°C for 2 mins., 20°C/min. to 0°C, then 4°C/min to 20°C, then 10°C/min. to 100°C, hold for 1 min. h) Helium carrier gas flow rate of 2.2ml/min 10 i) Inlet temperature 100°C j) Inlet pressure 19.35 psi k) Split ratio 25:1 1) FID temperature 310°C [0362] For non-hydrocarbon gases (e.g., argon, carbon dioxide and hydrogen sulfide) the GC 15 configuration consisted of the following: a) PTV (programmable temperature vaporization) inlet (front position of the GC) b) TCD (Thermal conductivity detector) front position of the GC c) GS-GasPro capillary column (30 meters x 0.32mm ID) d) 100μ1 fixed volume sample loop 20 e) six port gas sampling valve f) Oven program: 25°C hold for 2 min., then 10°C/min to 200°C, hold 1 min. g) Helium carrier gas flow rate of 4.1 ml/min. h) Inlet temperature 200°C i) Inlet pressure 14.9 psi 25 j) Splitless mode k) TCD temperature 250°C 122 [0363] For Examples 1-5, a stainless steel sample cylinder containing gas collected from theParr vessel (Figure 18) was fitted with a two stage gas regulator (designed for lecture bottle use)to reduce gas pressure to approximately twenty pounds per square inch. A septum fitting waspositioned at the outlet port of the regulator to allow withdrawal of gas by means of a Hamiltonmodel 1005 gas-tight syringe. Both the septum fitting and the syringe were purged with gas fromthe stainless steel sample cylinder to ensure that a representative gas sample was collected. Thegas sample was then transferred to a stainless steel cell (septum cell) equipped with a pressuretransducer and a septum fitting. The septum cell was connected to the fixed volume sample loopmounted on the GC by stainless steel capillary tubing. The septum cell and sample loop wereevacuated for approximately 5 minutes. The evacuated septum cell was then isolated from theevacuated sample loop by closure of a needle valve positioned at the outlet of the septum cell.The gas sample was introduced into the septum cell from the gas-tight syringe through theseptum fitting and a pressure recorded. The evacuated sample loop was then opened to thepressurized septum cell and the gas sample allowed to equilibrate between the sample loop andthe septum cell for one minute. The equilibrium pressure was then recorded, to allow calculationof the total moles of gas present in the sample loop before injection into the GC inlet. Thesample loop contents were then swept into the inlet by Helium carrier gas and componentsseparated by retention time in the capillary column, based upon the GC oven temperatureprogram and carrier gas flow rates.

[0364] Calibration curves, correlating integrated peak areas with concentration, weregenerated for quantification of gas compositions using certified gas standards. For hydrocarbongases, standards containing a mixture of methane, ethane, propane, butane, pentane and hexane ina helium matrix in varying concentrations (parts per million, mole basis) were injected into theGC through the fixed volume sample loop at atmospheric pressure. For non-hydrocarbon gases,standards containing individual components, i.e., carbon dioxide in helium and hydrogen sulfidein natural gas, were injected into the GC at varying pressures in the sample loop to generatecalibration curves.

[0365] The hydrocarbon gas sample molar percentages reported in Figure 16 were obtainedusing the following procedure. Gas standards for methane, ethane, propane, butane, pentane andhexane of at least three varying concentrations were run on the gas chromatograph to obtain peakarea responses for such standard concentrations. The known concentrations were then correlatedto the respective peak area responses within the Chemstation software to generate calibrationcurves for methane, ethane, propane, butane, pentane and hexane. The calibration curves were 123 plotted in Chemstation to ensure good linearity (R2 > 0.98) between concentration and peakintensity. A linear fit was used for each calibrated compound, so that the response factorbetween peak area and molar concentration was a function of the slope of the line as determinedby the Chemstation software. The Chemstation software program then determined a responsefactor relating GC peak area intensity to the amount of moles for each calibrated compound. Thesoftware then determined the number of moles of each calibrated compound from the responsefactor and the peak area. The peak areas used in Examples 1-5 are reported in Tables 2, 4,5,7,and 9. The number of moles of each identified compound for which a calibration curve was notdetermined (i.e., iso-butane, iso-pentane, and 2-methyl pentane) was then estimated using theresponse factor for the closest calibrated compound (i.e., butane for iso-butane; pentane for iso-pentane; and hexane for 2-methyl pentane) multiplied by the ratio of the peak area for theidentified compound for which a calibration curve was not determined to the peak area of thecalibrated compound. The values reported in Figure 16 were then taken as a percentage of thetotal of all identified hydrocarbon gas GC areas (i.e., methane, ethane, propane, iso-butane, n-butane, iso-pentane, n-pentane, 2-methyl pentane, and n-hexane) and calculated molarconcentrations. Thus the graphed methane to normal C6 molar percentages for all of theexperiments do not include the molar contribution of the unidentified hydrocarbon gas specieslisted in.Tables 2, 4, 5, 7, or 9 (e.g., peak numbers 2, 6, 8-11, 13, 15-22, 24-26, and 28-78 inTable 2).

[0366] Liquid samples collected during the heating tests as described in Examples 1, 3 and 4were analyzed by whole oil gas chromatography (WOGC) according to the following procedure.Samples, QA/QC standards and blanks (carbon disulfide) were analyzed using an Ultra 1 MethylSiloxane column (25 m length, 0.32 pm diameter, 0.52 pm film ·thickness) in an Agilent 6890GC equipped with a split/splitless injector, autosampler and flame ionization detector (FID).Samples were injected onto the capillary column in split mode with a split ratio of 80:1. The GCoven temperature was kept constant at 20°C for 5 min, programmed from 20°C to 300 °C at a rateof 5°C.min‘', and then maintained at 300 °C for 30 min (total run time = 90 min.). The injectortemperature was maintained at 300°C and the FED temperature set at 310 °C. Helium was used ascarrier gas at a flow of 2.1 mL min'1. Peak identifications and integrations were performed usingChemstation software Rev.A.10.02 [1757] (Agilent Tech. 1990-2003) supplied with the Agilentinstrument.

[0367] Standard mixtures of hydrocarbons were analyzed in parallel by the WOGC methoddescribed above and by an Agilent 6890 GC equipped with a split/splitless injector, auto sampler 124 and mass selective detector (MS) under the same conditions. Identification of the hydrocarboncompounds was conducted by analysis of the mass spectrum of each peak from the GC-MS.Since conditions were identical for both instruments, peak identification conducted on the GC-MS could be transferred to the peaks obtained on the GC-FID. Using these data, a compoundtable relating retention time and peak identification was set up in the GC-FID Chemstation. Thistable was used for peak identification.

[0368] The gas chromatograms obtained on the liquid samples (Figures 4, 9 and 11) wereanalyzed using a pseudo-component technique. The convention used for identifying eachpseudo-component was to integrate all contributions from normal alkane to next occurringnormal alkane with the pseudo-component being named by the late eluting n-alkane. Forexample, the C-10 pseudo-component would be obtained from integration beginning just pastnormal&amp;#1470;C9 and continue just through normal-ClO. The carbon number weight % and mole %values for the pseudo-components obtained in this manner were assigned using correlationsdeveloped by Katz and Firoozabadi (Katz, D.L., and A. Firoozabadi, 1978. Predicting phasebehavior of condensate/crude-oil systems using methane interaction coefficients, J. PetroleumTechnology (Nov. 1978), 1649-1655). Results of the pseudo-component analyses for Examples1,3 and 4 are shown in Tables 10,11 and 12. '[0369] An exemplary pseudo component weight percent calculation is presented below withreference to Table 10 for the CIO pseudo component for Example 1 in order to illustrate thetechnique. First, the C-10 pseudo-component total area is obtained from integration of the areabeginning just past normal-C9 and continued just through normal-CIO as described above. Thetotal integration area for the CIO pseudo component is 10551.700 pico-ampere-seconds (pAs).The total CIO pseudo component integration area (10551.700 pAs) is then multiplied by the CIOpseudo component density (0.7780 g/ml) to yield an "area X density" of 8209.22 pAs g/ml.Similarly, the peak integration areas for each pseudo component and all lighter listed compounds(i.e., nC3, iC4, nC4, iC5 &amp;amp; nC5) are determined and multiplied by their respective densities toyield "area X density" numbers for each respective pseudo component and listed compound. Therespective determined "area X density" numbers for each pseudo component and listedcompound is then summed to determine a "total area X density" number. The "total area Xdensity" number for Example 1 is 96266.96 pAs g/ml. The CIO pseudo component weightpercentage is then obtained by dividing the CIO pseudo component "area X density" number(8209.22 pAs g/ml) by the "total area X density" number (96266.96 pAs g/ml) to obtain the CIOpseudo component weight percentage of 8.53 weight percent. 125 [0370] An exemplary pseudo component molar percent calculation is presented below withreference to Table 10 for the CIO pseudo component for Example 1 in order to further illustratethe pseudo component technique. First, the C-10 pseudo-component total area is obtained fromintegration of the area beginning just past normal-C9 and continued just through normal-CIO as5 described above. The total integration area for the CIO pseudo component is 10551.700 pico-ampere-seconds (pAs). The total CIO pseudo component integration area (10551.700 pAs) isthen multiplied by the CIO pseudo component density (0.7780 g/ml) to yield an "area X density"of 8209.22 pAs g/ml. Similarly, the integration areas for each pseudo component and all lighterlisted compounds (i.e., nC3, iC4, nC4, iC5 &amp;amp; nC5) are determined and multiplied by their10 respective densities to yield "area X density" numbers for each respective pseudo component andlisted compound. The CIO pseudo component "area X density" number (8209.22 pAs g/ml) isthen divided by the CIO pseudo component molecular weight (134.00 g/mol) to yield a CIOpseudo component "area X density / molecular weight" number of 61.26 pAs mol/ml. Similarly,the "area X density" number for each pseudo component and listed compound is then divided by15 such components or compounds respective molecular weight to yield an "area X density /molecular weight" number for each respective pseudo component and listed compound. Therespective determined "area X density / molecular weight" numbers for each pseudo componentand listed compound is then summed to determine a "total area X density / molecular weight”number. The total "total area X density / molecular weight" number for Example 1 is 665.28 pAs20 mol/ml. The CIO pseudo component molar percentage is then obtained by dividing the CIOpseudo component "area X density / molecular weight" number (61.26 pAs mol/ml) by the "totalarea X density / molecular weight" number (665.28 pAs mol/ml) to obtain the CIO pseudocomponent molar percentage of 9.21 molar percent.

Table 10

Pseudo-components for Example 1 - GC of liquid - 0 stress

Component Area (cts.) Area % Avg. BoilingPt. (°F) Density (e/ml) MolecularWt. (e/mol) Wt. % Mol % nC3 41.881 0.03 -43.73 0.5069 44.10 0.02 0.07 >c« 120.873 0.10 10.94 0.5628 58.12 0.07 0.18 nC4 805.690 0.66 31.10 0.5840 58.12 0.49 1.22 iC5 1092.699 0.89 82.13 0.6244 72.15 0.71 1.42 nCj 2801.815 2.29 96.93 0.6311 72.15. 1.84 3.68 Pseudo C6 7150.533 5.84 147.00 0.6850 84.00 5.09 8.76 Pseudo C7 10372.800 8.47 197.50 0.7220 96.00 7.78 11.73 Pseudo C8 11703.500 9.56 242.00 0.7450 107.00 9.06 12.25 Pseudo G) 11776.200 9.61 288.00 0.7640 121.00 9.35 11.18 Pseudo C,0 10551.700 8.61 330.50 0.7780 134.00 8.53 9.21 Pseudo Cn 9274.333 7.57 369.00 0.7890 147.00 7.60 7.48 &#1490;! Pseudo C 8709.231 7.11 407.00 0.8000 161.00 7.24 6.50 Pseudo C!3 7494.549 6.12 441.00 0.8110 175.00 6.31 5.22 Pseudo C!4 6223.394 5.08 475.50 0.8220 190.00 5.31 4.05 Pseudo C|5 6000.179 4.90 511.00 0.8320 206.00 5.19 3.64 Pseudo C|6 5345.791 4.36 542.00 0.8390 222.00 4.66 3.04 Pseudo Cl7 4051.886 3.31 572.00 0.8470 237.00 3.57 2.18 Pseudo C!8 3398.586 . 2.77 595.00 0.8520 251.00 3.01 1.73 Pseudo C!9 2812.101 2.30 617.00 0.8570 263.00 2.50 1.38 Pseudo C20 2304.651 1.88 640.50 0.8620 275.00 2.06 1.09 Pseudo C21 2038.925 1.66 664.00 0.8670 291.00 1.84 0.91 Pseudo C22 1497.726 1.22 686.00 0.8720 305.00 1.36 0.64 Pseudo Cj3 1173.834 0.96 707.00 0.8770 318.00 1.07 0.49 Pseudo C24 822.762 0.67 727.00 0.8810 331.00 0.75 0.33 Pseudo C2s 677.938 0.55 747.00 0.8850 345.00 0.62 0.26 Pseudo C26 532.788 0.43 766.00 0.8890 359.00 0.49 0.20 Pseudo C27 459.465 0.38 784.00 0.8930 374.00 0.43 0.16 Pseudo C2! 413.397 0.34 802.00 0.8960 388.00 0.38 0.14 Pseudo C29 522.898 0.43 817.00 0.8990 402.00 0.49 0.18 Pseudo C30 336.968 0.28 834.00 0.9020 416.00 0.32 0.11 Pseudo C31 322.495 0.26 850.00 0.9060 430.00 0.30 0.10 Pseudo C32 175.615 0.14 866.00 0.9090 444.00 0.17 0.05 Pseudo C33 165.912 0.14 881.00 0.9120 458.00 0.16 0.05 Pseudo C34 341.051 0.28 895.00 0.9140 472.00 0.32 0.10 Pseudo C35 286.861 0.23 908.00 0.9170 486.00 0.27 0.08 Pseudo C36 152.814 0.12 922.00 0.9190 500.00 0.15 0.04 Pseudo C37 356.947 0.29 934.00 0.9220 514.00 0.34 0.10 Pseudo C38 173.428 0.14 947.00 0.9240 528.00 0.17 0.05 Totals 122484.217 100.00 100.00 100.00

Table 11

Pseudo-components for Example 3 - GC of liquid - 400 psi stress

Component Area Area% Avg. BoilingPt. (°F) Density (e/ml) Molecular Wt.(e/mol) Wt.% Mol % /1C3 35.845 0.014 -43.730 0.5069 44.10 0.01 0.03 iC&lt; 103.065 0.041 10.940 0.5628 58.12 0.03 0.07 nCA 821.863 0.328 31.100 0.5840 58.12 0.24 0.62 (C5 1187.912 0.474 82:130 0.6244 72.15 0.37 0.77 &amp;#1524;c5 3752.655 1.498 96.930 0.6311 72.15 1.20 2.45 Pseudo C6 12040.900 4.805 147.000 0.6850 84.00 4.17 7.34 Pseudo C7 20038.600 7.997 197.500 0.7220 96.00 7.31 11.26 Pseudo C» 24531.500 9.790 242.000 0.7450 107.00 9.23 12.76 Pseudo C; 25315.000 10.103 288.000 0.7640 121.00 9.77 11.94 Pseudo C,0 22640.400 9.035 330.500 0.7780 134.00 8.90 9.82 Pseudo C&amp;#1524; 20268.100 8.089 369.000 0.7890 147.00 8.08 8.13 Pseudo C]2 18675.600 7.453 407.000 0.8000 161.00 7.55 6.93 Pseudo C!j 16591.100 6.621 441.000 0.8110 175.00 6.80 5.74 Pseudo C!4 13654.000 5.449 475.500 0.8220 190.00 5.67 4.41 Pseudo C!5 13006.300 5.191 511.000 0.8320 206.00 5.47 3.92 Pseudo C16 11962.200 4.774 542.000 0.8390 222.00 5.07 3.38 Pseudo C!7 8851.622 3.533 572.000 0.8470. 237.00 3.79 2.36 Pseudo C!8 7251.438 2.894 595.000 0.8520 251.00 3.12 1.84 Pseudo C]9 5946.166 2.373 617.000 0.8570 263.00 2.57 1.45 Pseudo C20 4645.178 1.854 640.500 0.8620 275.00 2.02 1.09 Pseudo C21 4188.168 1.671 664.000 0.8670 291.00 1.83 0.93 Pseudo C22 2868.636 1.145 686.000 0.8720 305.00 1.26 0.61 Pseudo C2j 2188.895 0.874 707.000 0.8770 318.00 0.97 0.45. Pseudo C24 1466.162 0.585 727.000 0.8810 331.00 0.65 0.29 Pseudo C25 1181.133 0.471 747.000 0.8850 345.00 0.53 0.23 Pseudo C26 875.812 0.350 766.000 0.8890 359.00 0.39 0.16 Pseudo C27 617.103 0.246 784.000 0.8930 374.00 0.28 0.11 Pseudo C2b 538.147 0.215 802.000 0.8960 388.00 0.24 0.09 Pseudo C29 659.027 0.263 817.000 0.8990 402.00 0.30 0.11 Pseudo Cjo 1013.942 0.405 834.000 0.9020 416.00 0.46 0.16 Pseudo C31 761.259 0.304 850.000 0.9060 430.00 0.35 0.12 Pseudo C32 416.031 0.166 866.000 0.9090 444.00 0.19 0.06 Pseudo C33 231.207 0.092 881.000 0.9120 458.00 0.11 0.03 Pseudo C34 566.926 0.226 895.000 0.9140 472.00 0.26 0.08 Pseudo C35 426.697 0.170 908.000 0.9170 486.00 0.20 0:06 Pseudo C36 191.626 0.076 922.000 0.9190 500.00 0.09 0.03 Pseudo C37 778.713 0.311 934.000 0.9220 514.00 0.36 0.10 Pseudo C38 285.217 0.114 947.000 0.9240 528.00 0.13 0.04 Totals 250574.144 100.000 100.00 100.00 — 5 WO 2008/143745 PCTAJS2008/005008 128

Table 12

Pseudo-Components for Example 4 - GC of Liquid -1000 psi stress

Component Area Area % Avg. BoilingPt.(&amp;#1524;F) Density (g/ml) Molecular Wl.(g/raol) WL % Mol % /1C3 44.761 0.023 -43.730 0.5069 44.10 0.01 0.05 iC4 117.876 0.060 10.940 0.5628 58.12 0.04 0.11 /1C4 927.866 0.472 31.100 0.5840 58.12 0.35 0.87 &amp;#1523;C5 1082.570 0.550 82.130 0.6244 72.15 0.44 0.88 nCs 3346.533 . 1.701 96.930 0.6311 72.15 1.37 2.74 Pseudo C6 9579.443 4.870 147.000 0.6850 84.00 4.24 7.31 Pseudo C7 16046.200 8.158 197.500 0.7220 96.00 7.49 11.29 Pseudo Cg 19693.300 10.012 242.000 0.7450 107.00 9.48 12.83 Pseudo C9 20326.300 10.334 288.000 0.7640 121.00 10.04 12.01 Pseudo C!o 18297.600 9.302 330.500 0.7780 134.00 9.20 9.94 Pseudo C&amp;#1524; 16385.600 8.330 369.000 0.7890 147.00 8.36 8.23 Pseudo C|2 15349.000 7.803 407.000 0.8000 161.00 7.94 7.14 Pseudo C!j 13116.500 6.668 441.000 0.8110 175.00 6.88 5.69 Pseudo C,« 10816.100 5.499 475.500 0.8220 190.00 5.75 4.38 Pseudo C!5 10276.900 5.225 511.000 0.8320 206.00 5.53 3.88 Pseudo C|6 9537.818 .4.849 542.000 . 0.8390 222.00 5.17 3.37 Pseudo C!7 6930.611 3.523 572.000 0.8470 237.00 3.79 2.32 Pseudo C!g 5549.802 2.821 595.000 0.8520 251.00 3.06 1,76 Pseudo C!9 4440.457 2.257 617.000 0.8570 263.00 2.46 1.35 Pseudo Cjo . 3451.250 1.755 640.500 0.8620 275.00 1.92 1.01 Pseudo C21 3133.251 1.593 664.000 • 0.8670 291.00 1.76 0.87 Pseudo C22 2088.036 1.062 686.000 0.8720 305.00 1.18 0.56 Pseudo C23 1519.460 0.772 707.000 0.8770 318.00 0.86 0.39 Pseudo C24 907.473 0.461 727.000 0.8810 331.00 0.52 0.23 Pseudo C25 683.205 0.347 747.000 0.8850 345.00 0.39 0.16 Pseudo C26 493.413 0.251 766.000 0.8890 359.00 0.28 0.11 Pseudo C27 326.831 0.166 784.000 0.8930 374.00 0.19 0.07 Pseudo C2g 272.527 0.139 802.000 0.8960 388.00 0.16 0.06 Pseudo C29 291.862 0.148 817.000 0.8990 402.00 0.17 0.06 Pseudo C30 462.840 0.235 834.000 0.9020 416.00 0.27 0.09 Pseudo Ο&amp;#1524; 352.886 0.179 850.000 0.9060 430.00 0.21 0.07 Pseudo C32 168.635 0.086 866.000 0.9090 444.00 0.10 0.03 Pseudo C33 67.575 0.034 881.000 0.9120 458.00 0.04 0.01 Pseudo C34 95.207 0.048 895.000 0.9140 472.00 0.06 0.02 Pseudo C35 226.660 0.115 908.000 0.9170 486.00 0.13 0.04 Pseudo C36 169.729 0.086 922.000 0.9190 500.00 0.10 0.03 Pseudo C37 80.976 0.041 934.000 0.9220 514.00 0.05 0.01 Pseudo C3g 42.940 0.022 947.000 0.9240 528.00 0.03 0.01 Totals 196699.994 100.000 100.00 100.00 129 [0371] TOC and Rock-eval tests were performed on specimens from oil shale block CM-IBtaken at the same stratigraphic interval as the specimens tested by the Parr heating methoddescribed in Examples 1-5. These tests resulted in a TOC of 21% and a Rock-eval HydrogenIndex of 872 mg/g-toc.

[0372] The TOC and rock-eval procedures described below were performed on the oil shalespecimens remaining after the Parr heating tests described in Examples 1-5. Results are shown inTable 13.

[0373] The Rock-Eval pyrolysis analyses described above were performed using thefollowing procedures. Rock-Eval pyrolysis analyses were performed on calibration rockstandards (IFP standard #55000), blanks, and samples using a Delsi Rock-Eval Π instrument.Rock samples were crushed, micronized, and air-dried before loading into Rock-Eval crucibles.Between 25 and lOOmg of powdered-rock samples were loaded into the crucibles depending onthe total organic carbon (TOC) content of the sample. Two or three blanks were run at thebeginning of each day to purge the system and stabilize the temperature. Two or three samplesof DFP calibration standard #55000 with weight of 100 +/-1 mg were run to calibrate the system.If the Rock-Eval T™* parameter was 419° C +/- 2°C on these standards, analyses proceeded withsamples. The standard was also run before and after every 10 samples to monitor theinstrument's performance.

[0374] The Rock-Eval pyrolysis technique involves the rate-programmed heating of apowdered rock sample to a high temperature in an inert (helium) atmosphere and thecharacterization of products generated from the thermal breakdown of chemical bonds. Afterintroduction of the sample the pyrolysis oven was held isothermally at 300°C for three minutes.Hydrocarbons generated during this stage are detected by a flame-ionization detector (HD)yielding the S! peak. The pyrolysis-oven temperature was then increased at a gradient of25°C/minute up to 550°C, where the oven was held isothermally for one minute. Hydrocarbonsgenerated during this step were detected by the FID and yielded the S2 peak.

[0375] Hydrogen Index (HI) is calculated by normalizing the S2 peak (expressed asmghydrocarbons/grock) to weight % TOC (Total Organic Carbon determined independently) asfollows: HI ={S2/TOC)* 100 WO 2008/143745 where HI is expressed as mghydrocarbons/g&amp;#1470;roc [0376] Total Organic Carbon (TOC) was determined by well known methods suitable forgeological samples &amp;#1470; i.e., any carbonate rock present was removed by acid treatment followed bycombustion of the remaining material to produce and measure organic based carbon in the form5 of C02.

Table 13 TOC and Rock Eval Results on Oil Shale Specimens after the Parr Heating Tests.

Example 1 Example 2 Example 3 Example 4 Example 5 TOC (%) 12.07 10.83 10.62 11.22 11.63 HI (mg/g-toc) 77 83 81 62 77 10 [0377] The API gravity of Examples 1-5 was estimated by estimating the room temperature

specific gravity (SG) of the liquids collected and the results are reported in Table 14. The API gravity was estimated from the determined specific gravity by applying the following formula: API gravity =(141.5/SG)-131.5 [0378] The specific gravity of each liquid sample was estimated using the following 15 . procedure. An empty 50 μ\ Hamilton Model 1705 gastight syringe was weighed on a Mettler AE163 digital balance to determine the empty syringe weight. The syringe was then loaded byfilling the syringe with a volume of liquid. The volume of liquid in the syringe was noted. Theloaded syringe was then weighed. The liquid sample weight was then estimated by subtractingthe loaded syringe measured weight from the measured empty syringe weight. The specific20 gravity was then estimated by dividing the liquid sample weight by the syringe volume occupiedby the liquid sample.

Table 14

Estimated API Gravity of liquid samples from Examples 1-5

Example Example 1 Example 2 Example 3 Example 4 Example 5 API Gravity 29.92 30.00 27.13 32.70 30.00 25 [0379] The above-described processes may be of merit in connection with the recovery of hydrocarbons in the Piceance Basin of Colorado. Some have estimated that in some oil shaledeposits of the Western United States, up to 1 million barrels of oil may be recoverable per WO 2008/143745 surface acre. One study has estimated the oil shale resource within the nahcolite-bearing portionsof the oil shale formations of the Piceance Basin to be 400 billion barrels of shale oil in place.Overall, up to 1 trillion barrels of shale oil may exist in the Piceance Basin alone.

[0380] Certain features of the present inventions are described in terms of a set of numerical5 upper limits and a set of numerical lower limits. It should be appreciated that ranges formed byany combination of these limits are within the scope of the invention unless otherwise indicated.Although some of the dependent claims have single dependencies in accordance with U.S.practice, each of the features in any of such dependent claims can be combined with each of thefeatures of one or more of the other dependent claims dependent upon the same independent10 claim or claims. : [0381] While it will be apparent that the invention herein described is well calculated toachieve the benefits and advantages set forth above, it will be appreciated that the invention issusceptible to modification, variation and change without departing from the spirit thereof. ν' ;&amp;#1502;&amp;#1513;&amp;#1508;&amp;#1496;&amp;#1497;&amp;#1501; &amp;#1492; &amp;#1493;&amp;#1491;&amp;#1504;&amp;#1493; &amp;#1492;&amp;#1506;&amp;#1514;&amp;#1511; &amp;#1513;&amp;#1504;&amp;#1505;&amp;#1491;&amp;#1511; &amp;#1489;&amp;#1513;&amp;#1500;&amp;#1502;&amp;#1493;&amp;#1514;&amp;#1493; &amp;#1489;&amp;#1497;&amp;#1493;&amp;#1501; &amp;#1493;&amp;#1489;&amp;#1513;&amp;#1504;&amp;#1492; &amp;#1492;&amp;#1502;&amp;#1510;&amp;#1493;&amp;#1497;&amp;#1504;&amp;#1497;&amp;#1501;; &amp;#1502;&amp;#1502;&amp;#1493;&amp;#1495;&amp;#1513;&amp;#1489;&amp;#1514; &amp;#1502;&amp;#1492;&amp;#1497;&amp;#1502;&amp;#1504;&amp;#1492; &amp;#1502;&amp;#1492;&amp;#1502;&amp;#1505;&amp;#1502;&amp;#1498; &amp;#1492;&amp;#1502;&amp;#1510;&amp;#1493;&amp;#1497; &amp;#1489;&amp;#1514;&amp;#1497;&amp;#1511;,&amp;#1500;&amp;#1504;&amp;#1493;&amp;#1492;&amp;#1500; &amp;#1492;&amp;#1489;&amp;#1491;&amp;#1497;&amp;#1511;&amp;#1493;&amp;#1514; &amp;#1489;&amp;#1502;&amp;#1513;&amp;#1512;&amp;#1491; &amp;#1492;&amp;#1502;&amp;#1513;&amp;#1508;&amp;#1496;&amp;#1497;&amp;#1501;.&amp;#1493;&amp;#1505; ;&amp;#1513;&amp;#1512;&amp;#1491; &amp;#1492;&amp;#1502;&amp;#1513;&amp;#1508;&amp;#1496;&amp;#1497;&amp;#1501;(&amp;#1495;&amp;#1514;&amp;#1497;&amp;#1502;&amp;#1492; &amp;#1502;&amp;#1493;&amp;#1505;&amp;#1491;&amp;#1497;&amp;#1514;).