Downhole burners for in situ conversion of organic-rich rock formations

מבערים לבארות בעומק הפיר עבוד חפיפה ״תוך־בארית״ של מופעי שלע עשיר בחומר אורגני

Downhole burners for IN SITU conversion of organic-rich rock formations

ExxonMobil Upstream Research Company C.196000 PCTAJS2008/005056 ־ ן * W0 2008/143749

DOWNHOLE BURNERS 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.60/930,308 filed May 15, 2007. That application is titled “Downhole Burners for In SituConversion 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. 2007EM020] entitled "Downhole Burner WellsFor In Situ Conversion of Organic-Rich Rock Formations", which claims the benefit of U. S.Provisional Patent Application Serial No. 60/930,311, filed May 15, 2007, the disclosures ofwhich are hereby incorporated herein in their entirety by reference.

BACKGROUND OF THE INVENTION

Field of the Invention [0003] The present invention relates to the field of hydrocarbon recovery from subsurfaceformations. 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 combustible fuel.

Discussion of the Art [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.

[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 UnitedStates. Such formations are notably found in Wyoming, Colorado, and Utah. Oil shale PCT/US2008/005Q56 -2- WO 2008/143749 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.

[0007] The decomposition rate of kerogen to produce mobile hydrocarbons is temperaturedependent. Temperatures generally in excess of 270° C (518° F) over the course of many monthsmay be requited for substantial conversion. At higher temperatures substantia] 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 andgas. 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 aswell 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,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 thisresearch 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 Ljungstrompatent 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 tothe surrounding oil shale. Thus, the heat supply channels served as early heat injection wells. ! PCT/US2008/005056 -3 WO 2008/143749

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, the“aggregate” was heated to between 500° and 1,000° C in some applications. 5 [0012] Along with the heat injection wells, fluid producing wells were also completed in near proximity 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 wellboresthrough the Swedish Shale Oil Company. A full scale plant was developed that operated from 10 1944 into the 1950's. (See G. Salamonsson, “The Ljungstrom In Situ Method for Shale-Oil

Recovery,” 2Bd Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute ofPetroleum. London, p. 260-280 (1951), the entire disclosure of which is incorporated herein byreference.) [0014] Additional in situ methods have been proposed. These methods generally involve the15 injection of heat and/or solvent into a subsurface oil shale formation. Heat may be in the form of heated 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 theΓΓΤ Research Institute in Chicago, Illinois) or oxidant injection to support in situ combustion. In20 some 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. Slusscr 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.), heatfracturing (see U.S. Pat. No. 3,284,281 to R.W. Thomas), and steam fracturing (see U.S. Pat. No.25 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 that“[cjontrary to the implications of . . . prior teachings and beliefs . . . the presently described 30 conductive heating process is economically feasible for use even in a substantially impermeablesubterranean oil shale." (col. 6, In. 50-54). Despite this declaration, it is noted that few, if any,commercial in situ shale oil operations have occurred other than Ljungstrom’s enterprise. The

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PCT/US2008/005056 -4- WO 2008/143749 '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-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, [0017] A need exists for improved processes for the production of shale oil. In addition, aneed exists for improved downhole burners for converting kerogen or other solid organic matterin a subsurface formation into hydrocarbon fluids.

SUMMARY OF THE INVENTION

[0018] A method for in situ heating of a selected portion of an organic-rich rock formation isprovided. In one aspect, the method may include providing casing in a wellbore located at leastpartially within the organic-rich rock formation. The casing extends to a depth within or belowthe selected portion of the organic-rich rock formation. The method may further includeproviding a tubing within the casing. The tubing forms a first annulus between the tubing and thesurrounding casing.

[0019] The method employs an oxidant and a combustible fuel. The method then furtherincludes setting an amount of stoichiometric combustion excess of either the oxidant or thecombustible fuel so as to provide a more uniform temperature profile in the first annulus alongthe selected portion of the organic-rich rock formation. The oxidant and the combustible fuel areinjected into the wellbore, with either the oxidant or the combustible fuel being substantially inthe amount of stoichiometric combustion excess.

[0020] The method may further include providing hardware in the wellbore so as to cause theoxidant and the combustible fuel to mix and to combust into flue gas. Combustion occurs at afirst combustion depth located substantially within the selected portion of the organic-rich rockformation. The flue gas is moved up the first annulus between the tubing and the surroundingcasing.

[0021] The method may also include providing insulation along at least a portion of thetubing below the first combustion depth. This serves to reduce the heat transfer coefficient PCT/US2008/005056 -5- WO 2008/143749 between the flue gas in the first annulus and the flue gas within the tubing during circulation ofthe flue gas up the first annulus. {0022] Also provided herein is an improved heater well for in situ heating of an organic-richrock formation. The heater well may include a casing in a wellbore located at least partiallywithin the organic-rich rock formation. The casing extends to a depth within or below theorganic-rich rock formation and is substantially sealed to the formation. The heater well mayfurther include a tubing within the casing. The tubing defines an annulus between the tubing andthe surrounding casing. A first tubular member resides within the tubing and extends to a firstdepth within the organic-rich rock formation.

[0023] The heater well may further include a (1) first burner proximate the bottom end of thefirst tubular member, and ¢2) a second tubular member residing within the tubing and extendingto a second depth within the organic-rich rock formation, wherein the second depth is lower thanthe first depth. The heater well may further include a second burner proximate a bottom end ofthe second tubular member. An insulation layer may be provided on the tubing proximate eachof the first depth and second depth. Preferably, thermal power capacities of the first and secondburners, spacing between the first and second burners, lengths of the insulation layers, orcombinations thereof are specified to create a substantially uniform temperature profile withinthe casing located along a selected portion of the organic-rich rock formation when the heaterwell is in operation. {0024) An alternate embodiment for a heater well for in situ heating of an organic-rich rockformation is provided. The heater well may include a casing in a wellbore located at leastpartially within the organic-rich rock formation. The casing extends to a depth within or belowthe organic-rich rock formation and is substantially sealed to the formation. The heater well mayfurther include a tubing within the casing. An annulus is defined between the tubing and thesurrounding casing. {0025] A first tubular member resides within the tubing. The tubular member extends at leastto a first depth within the organic-rich rock formation. A first burner is positioned proximate abottom end of the first tubular member. A second tubular member resides within the tubing andextends to a second depth within the organic-rich rock formation that is lower than the firstdepth. A second burner is positioned proximate a bottom end of the second tubular member at asecond depth within the formation. An insulation layer is placed on the tubing proximate each ofthe first depth and the second depth. Preferably, thermal power capacities of the first and secondburners, spacing between the first and second burners, lengths of the insulation layers, or PCT/US2008/005056 • 6 WO 2008/143749 combinations thereof are specified to create a substantially uniform temperature profile withinthe casing located along a selected portion of the organic-rich rock formation when the heaterwell is in operation.

[0026] A method of producing a hydrocarbon fluid is also provided herein. The method mayinclude heating an organic-rich rock formation in situ using a heater well, and producing ahydrocarbon fluid from the organic-rich rock formation In accordance with this embodiment, thehydrocarbon are at least partially generated as a result of pyrolysis of formation hydrocarbonslocated in the organic-rich rock formation.

[0027] In the alternate method, the heater well may include a casing in a wellbore located atleast partially within the organic-rich rock formation The casing extends to a depth within orbelow the organic-rich rock formation and is substantially sealed to the surrounding formation.The heater well may further include a tubing, within the casing. An annulus is formed between,the tubing and the surrounding casing. The heater well may further include a tubular memberresiding within the tubing. The tubular member extends at least to the organic-rich rockformation.

[0028] The heater well may further include (1) a first burner that is positioned along thetubular member at a first depth within the organic-rich rock formation, and (2) a second burnerpositioned along the tubular member at a second depth within the formation. The second depth isbelow the first depth.

[0029] An additional alternate embodiment for a method of producing a hydrocarbon fluid isdisclosed herein. The additional alternate method may include providing casing in a wellborelocated at least partially within an organic-rich rock formation. The casing extends to a depthwithin or below a selected portion of the formation. The method may further include providing atubing within the casing. A first annulus is defined between the tubing and the surroundingcasing. The method may further include injecting an oxidant and a combustible fuel into thewellbore. Either the oxidant or the combustible fuel is in stoichiometric combustion excess overthe other.

[0030] The additional alternate method may further include providing hardware in thewellbore. The hardware causes the oxidant and the combustible fuel to mix and to combust intoflue gas at a first combustion depth located substantially within the selected portion of theorganic-rich rock formation. In this way a selected portion of the organic-rich rock formation isheated. Flue gas is circulated up the first annulus between the tubing and the surrounding casing.This serves to further heat the selected portion of the organic-rich rock formation. PCT/US2008/005056 -7- WO 2008/143749 [0031] The additional alternate method may further include providing insulation on at least aportion of the tubing. The insulation is located below the first combustion depth, and reduces theheat transfer coefficient between the flue gas in the first annulus and the flue gas within thetubing. The method may further include producing a hydrocarbon fluid from the organic-richrock formation. The hydrocarbon fluid is at least partially generated as a result of pyrolysis offormation hydrocarbons located in the organic-rich rock formation due to the heating.

BRIEF DESCRIPTION OF THE DRAWINGS

[0032] So that the manner in which the features of the present inventions can be betterunderstood, certain drawings, graphs and flow charts are appended hereto. It is to be noted,however, that the drawings illustrate only selected embodiments of the inventions and aretherefore not to be considered limiting of scope, for the inventions may admit to other equallyeffective embodiments and applications.

[0033] 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.

[0034] 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.

[0035] 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.

[0036] Figure 4 is a plan view of an illustrative heater well pattern, around a production well.Two layers of heater wells are shown.

[0037] Figure 5 is a bar chart comparing one ton of Green River oil shale before and after asimulated in situ, retorting process.

[0038] Figure 6 is a process flow diagram of exemplary surface processing facilities for asubsurface formation development.

[0039] 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.

[0040] 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. PCT/US2008/005056 - 8 - WO 2008/143749 [0041] 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.

[0042] 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.

[0043] Figure 11 is a graph of the weight percent of normal alkane hydrocarbon compoundsocculting from normal-C6 to normal-C38 for laboratory experiments conducted at three differentstress levels.

[0044] Figure 12 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal-C6 to normal-C38 as compared to the normal-C20 hydrocarboncompound for laboratory experiments conducted at three different stress levels.

[0045] Figure 13 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal־C6 to normal־C38 as compared to the normal־C25 hydrocarboncompound for laboratory experiments conducted at three different stress levels.

[0046] 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 hydrocarboncompound for laboratory experiments conducted at three different stress levels.

[0047] 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.

[Q04B] Figure 16 is a bar graph showing the concentration, in molar percentage, of thehydrocarbon species present in the gas samples taken from duplicate laboratory experimentsconducted at three different stress levels.

[0049] Figure 17 is an exemplary view of the gold tube apparatus used in the unstressed Parrheating test described below in Example 1.

[0050] Figure 18 is a cross-sectional view of the Parr vessel used in Examples 1-5, describedbelow.

[0051] Figure 19 is gas chromatogram of gas sampled from Example 1.

[0052] Figure 20 is a whole oil gas chromatogram of liquid sampled from Example 1. PCT/US2008/005056 -9- WO 2008/143749 [0053] Figure 21 is an exemplary view of a Berea cylinder, Berea plugs, and an oil shale corespecimen as used in Examples 2-5.

[0054] Figure 22 is an exemplary view of the mini load frame and sample assembly used inExamples 2-5.

[0055] Figure 23 is gas chromatogram of gas sampled from Example 2.

[0056] Figure 24 is gas chromatogram of gas sampled from Example 3.

[0057] Figure 25 is a whole oil gas chromatogram of liquid sampled from Example 3.

[0056] Figure 26 is gas chromatogram of gas sampled from Example 4.

[0059] Figure 27 is a whole oil gas chromatogram of liquid sampled from Example 4.

[0060] Figure 28 is gas chromatogram of gas sampled from Example 5.

[0061] Figure 29 is a cross-sectional view of a heater well, in one embodiment. Here, aplurality of burners are disposed in a wellbore. The wellbore is completed through an organic-rich rock formation.

[0062] Figure 30 is a top view of the wellbore of Figure 29.

[0063] Figure 31 is a side view of one of the burners from the heater well of Figure 29. A cowl to contain a flame and to control oxidant mixing is seen disposed immediately below the burner.

[0064] Figure 32 is a cross-sectional view of a heater well in an alternate embodiment. Aplurality of burners is again disposed in a wellbore. The wellbore is completed through anorganic-rich rock formation.

[0065] Figure 33 is a side view of one of the burners from the heater well of Figure 32. Acowl is seen disposed immediately below the burner.

[0066] Figure 34A is a graph charting depth in a wellbore versus temperature. The depth inthe wellbore is charted relative to the location of a burner downhole. In this wellbore, a singleburner is used, and insulation is placed along the inner tubing below the burner. The averagetemperatures of the downward flow of gases within the tubing and in the upward flow of flue gasoutside of the tubing are compared.

[0067] Figure 34B is a graph charting depth in a wellbore versus temperature. The depth inthe wellbore is charted relative to the location of a burner downhole. In this wellbore, a singleburner is used, but no insulation is provided along the inner tubing. The average temperatures of

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PCT/US2008/005056 ־10 • WO 2008/143749 the downward flow of gases within the tubing and in the upward flow of flue gas outside of thetubing are compared.

[0068! Figure 34C is a graph charting depth in a wellbore versus temperature. The depth inthe wellbore is charted relative to the location of a burner downhole. In this wellbore, a singleburner is used, and insulation is placed along the inner tubing below the burner. A lowerinjection rate is used for the air as compared to the wellbores of Figures 34A and 34B. Theaverage temperatures of the downward flow of gases within the tubing and in the upward flow offlue gas outside of the tubing are compared.

[0069] Figure 34D is a graph charting depth in a wellbore versus temperature. The depth inthe wellbore is charted relative to the location of a burner downhole. In this wellbore, threeburners are used, and insulation is placed along the inner tubing below the uppermost burner.The average temperatures of the downward flow of gases within the tubing and in the upwardflow of flue gas outside of the tubing are compared.

[0070] Figure 35 is a side view of a portion of a wellbore having a downhole burner therein.The wellbore is shown to demonstrate the utility of the graph of Figure 34A.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions [0071] As used herein, the term "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.

[0072] 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.

[0073] 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, a WO2008/143749 . jj. PCT/US2008/005056 pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids.

[0074] 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.

[0075] 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.

[0076] As used herein, the term "heavy hydrocarbons" refers to hydrocarbon fluids that arehighly viscous at ambient conditions (15° C and 1 atm pressure). Heavy hydrocarbons mayinclude 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 generallyhave 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.

[0077] As used herein, the term "solid hydrocarbons" refers to any hydrocarbon material thatis found naturally in substantially solid form at formation conditions. Non-limiting examplesinclude kerogen, coal, shungites, asphaltites, and natural mineral waxes.

[0078] 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.

[0079] As used herein, the term "tar" refers to a viscous hydrocarbon that generally has aviscosity 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.

[0080] As used herein, the term "kerogen" refers to a solid, insoluble hydrocarbon thatprincipally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Oil shale contains kerogen.

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I PCT/US2008/005056 -12- WO 2008/143749 [0082} As used herein, the term "oil" refers to a hydrocarbon fluid containing a mixture ofcondensable hydrocarbons.

[0083] As used herein, the term "subsurface" refers to geologic strata occurring below theearth's surface. 5 [0084] As used herein, the term “hydrocarbon-rich formation” refers to any formation that contains more than trace amounts of hydrocarbons. For example, a hydrocarbon-rich formationmay 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. 10 [0085] As used herein, the term “organic-rich rock” refers to any rock matrix holding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but are not limited to,sedimentary rocks, shales, siltstones, sands, siliciiytes, carbonates, and diatomites.

[0086] 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- 15 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 theformation of interest. An overburden of underburden may include one or more different types ofsubstantially impermeable materials. For example, overburden and/or underburden may includerock, shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonate without 20 hydrocarbons). An overburden and/or an underburden may include a hydrocarbon-containinglayer that is relatively impermeable. In some cases, the overburden and/or underburden may bepermeable.

[0087] As used herein, the term “organic-rich rock formation” refers to any formationcontaining organic-rich rock. Organic-rich rock formations include, for example, oil shale 25 formations, coal formations, and tar sands formations.

[0088] As used herein, the term "pyrolysis” refers to the breaking of chemical bonds throughthe application of heat. For example, pyrolysis may include transforming a compound into oneor 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 be 30 obtained from molecular hydrogen, water, carbon dioxide, or carbon monoxide. Heat may betransferred to a section of the formation to cause pyrolysis. PCT/US20O8/0O5O56 ־13 WO 2008/143749 [0089] As used herein, the term "water-soluble minerals" refers to minerals that are soluble inwater. Water-soluble minerals include, for example, nahcolite (sodium bicarbonate), soda ash(sodium carbonate), dawsonite (NaAl(COj)(OH)2), or combinations thereof. Substantialsolubility may require heated water and/or a non-neutral pH solution.

[0090] As used herein, the term "formation water-soluble minerals" refers to water-solubleminerals that are found naturally in a formation.

[0091] As used herein, the term "migratory contaminant species" refers to species that aresoluble or moveable in water or an aqueous fluid, and are considered to be potentially harmful orof concern to human health or the environment. Migratory contaminant species may includeinorganic and organic contaminants, Organic contaminants may include saturated hydrocarbons,aromatic hydrocarbons, and oxygenated hydrocarbons. Inorganic contaminants may includemetal contaminants, and ionic contaminants of various types that may significantly alter pH orthe formation fluid chemistry. Aromatic hydrocarbons may include, for example, benzene,toluene, xylene, ethylbenzene, and tri-methylbenzene, and various types of polyaromatichydrocarbons such as anthracenes, naphthalenes, chrysenes and pyrenes. Oxygenatedhydrocarbons may include, for example, alcohols, ketones, phenols, and organic acids such ascarboxylic acid. Metal contaminants may include, for example, arsenic, boron, chromium,cobalt, molybdenum, mercury, selenium, lead, vanadium, nickel or zinc. Ionic contaminantsinclude, for example, sulfides, sulfates, chlorides, fluorides, ammonia, nitrates, calcium, iron,magnesium, potassium, lithium, boron, and strontium.

[0092] 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.

[0093] As used herein, the term "subsidence" refers to a downward movement of a surfacerelative to an initial elevation of the surface.

[0094] 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.

[0095] 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 turn 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. PCT/U S2008/005056 -14 ־ WO 2008/143749 [0096] 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 verticalin orientation, or oriented along any other plane.

[0097] 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 openingin the formation, may be used interchangeably with the term "wellbore.” [0098] As used herein, the term ,'cowl״ means a tubular body of any material or constructionhaving perforations or vents therein.

[099] As used herein, the term “targeted organic-rich rock formation” means a portion of anorganic-rich rock formation that has been chosen for in situ heating. The chosen portion may bedefined according to a given depth or range of depths, a given horizontal distance, or both.

[0100] As used herein with respect to temperature and downhole burners, the term “uniformtemperature” means that the temperature remains within a desired temperature range over aselected portion of an organic-rich rock formation.

Description of Specific Embodiments [0101] 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, such is intended to be illustrative only and is not to be construedas limiting the scope of the invention.

[0102] 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 rock formation may include formation hydrocarbons, including, for example,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 (sodium PCT/US2G08/005056 -15- WO 2008/143749 bicarbonate, or 2NaHC03), soda ash (sodium carbonate, or Na2C03) and dawsonite(NaAl(C03)(0H)2).

[0103] 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 1¢. The illustrative subsurface formation 16 contains formation hydrocarbons (suchas, for example, kerogen) and possibly valuable water-soluble minerals (such as, for example,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.

[0104] In order to access formation 16 and recover natural resources therefrom, a plurality ofwellbores 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.The completions may be either open or cased hole. The well completions may also includepropped or unpropped hydraulic fractures emanating therefrom.

[0105] 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.

[0106] 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 mn into and removed fromthe wellbores 14 to serve the various purposes. PCT/US2008/0050S6 - 16- WO 2008/143749 10107] A fluid processing facility 17 is also shown schematically. The fluid processingfacility 17 is equipped to receive fluids produced from the organic-rich rock formation 16through one or more pipelines or flow lines 18. The fluid processing facility 17 may includeequipment suitable for receiving and separating oil, gas, and water produced from the heatedformation. The fluid processing facility 17 may further include equipment for separating outdissolved water-soluble minerals and/or migratory contaminant species, including, for example,dissolved organic contaminants, metal contaminants, or ionic contaminants in the produced waterrecovered from the organic-rich rock formation 16. The contaminants may include, for example,aromatic hydrocarbons such as benzene, toluene, xylene, and tri-methylbenzene. Thecontaminants may also 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. Ioniccontaminant species may include, for example, sulfates, chlorides, fluorides, lithium, potassium,aluminum, ammonia, and nitrates.

[0108] In order to recover oil, gas, and sodium (or other) water-soluble minerals, a series ofsteps may be undertaken. Figure 2 presents a flow chart demonstrating a method of in situthermal recovery of oil and gas from an organic-rich rock formation 100, in one embodiment. Itis understood that the order of some of the steps from Figure 2 may be changed, and that thesequence of steps is merely for illustration.

[0109] 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.

[0110] The kerogen content of the 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. Subsurface permeability may also be PCT/US2008/0050S6 -17- WO 2008/143749 assessed via rock samples, outcrops, or studies of ground water flow. Furthermore theconnectivity of the development area to ground water sources may be assessed.

[0111! Next, a plurality of wellbores 14 is formed across the targeted development area 10.This step is shown schematically in box 115. The purposes of the wellbores 14 are set forthabove and need not be repeated. However, it is noted that for purposes of the wellbore formationstep of box 115, only a portion of the wells need be completed initially. For instance, at thebeginning of the project heat injection wells are needed, while a majority of the hydrocarbonproduction wells are not yet needed. Production wells may be brought in once conversionbegins, such as after 4 to 12 months of heating.

[0112] 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.

[0113] 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 bybox 130. Preferably, for in situ processes the heating of a production zone takes place over aperiod of months, or even four or more years.

[0114] 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 ofthe 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. Generatedgases include light alkanes, light alkenes, ¾, C02, CO, and NH3.

[0115] 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 beheated 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 sodium PCT/US2008/005056 ־18־ WO 2008/143749 carbonate (soda ash), a related sodium mineral. The process of converting nahcolite (sodiumbicarbonate) to soda ash (sodium carbonate) is described herein.

[0116] In connection with the heating step 130, the rock formation 16 may optionally befractured to aid heat transfer or later hydrocarbon fluid production. The optional fracturing stepis 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.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 planarsource for heating. The WO 2005/010320 patent publication incorporated above describes oneuse of hydraulic fracturing.

[0117] 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,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.

[0118] After certain wellbores 14 have been designated as oil and gas production wells, oiland/or gas is produced from the wellbores 14. The oil and/or gas production process is shown atbox 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) withinthe formation.

[0119] 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 include PCT/US2008/005056 ־19־ WO 2008/143749 dissolved inorganic salts of chloride, sulfates and carbonates of Group I and II elements of ThePeriodic 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 gasproduction. 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.

[0120] Next, optionally water or an aqueous fluid is injected through the water injectionwells 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 thenahcolite-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.

[0121] Along with the designation of certain wellbores 14 as water injection wells, the designengineers may also designate certain wellbores 14 as water or water-soluble mineral solutionproduction 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 dissolvedsoda 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).

[0122] Temporary control of the migration of the migratory contaminant species, especiallyduring the pyrolysis process, can be obtained via placement of the injection and production wells14 such that fluid flow out of the heated zone is minimized. Typically, this involves placinginjection wells at the periphery of the heated zone so as to cause pressure gradients which preventflow inside the heated zone from leaving the zone. PCT/US2008/005056 -20- WO 2008/143749 (0123} 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 oilshale 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 aquit&amp;amp;rds and oil shale zones. A plurality ofwells (28,29,30 and 31) is shown traversing vertically downward through the aquifers. One ofthe 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.

[0124] 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 well31 forces water into the previously heated oil shale 33 so that water-soluble minerals andmigratory contaminants species are swept to the water production well 30. The water may thenbe processed in a facility 34 wherein the water-soluble minerals (e.g. nahcolite or soda ash) andthe migratory contaminants may be substantially removed from the water stream. Water is thenreinjected 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.

[0125] 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.

[0126] 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 the WO 2008/143749 _ 21 - PCT/US2008/0050S6 formation. 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.

[0127] 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 describedherein, however, may also include selecting and treating layers that may include layerssubstantially free of formation hydrocarbons or thin layers of formation hydrocarbons.

[0128] 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.

[0129] 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.

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[0130] Subsurface formation permeability may also be assessed via rock samples, outcrops,30 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. PCT/US2008/005056 -22- WO 2008/143749 [0131] 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.

[0132] 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 substantiallyreduce the temperature of the rock formation. This, in tum, prevents the pyrolyzation 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.

[0133] The use of subsurface freezing to stabilize poorly consolidated soils or to provide abarrier to fluid flow is known in the art. Shell Exploration and Production Company hasdiscussed the use of freeze walls for oil shale production in several patents, including U.S. PatNo. 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.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.

[0134] 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. Theheater 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.

[0135] The different wells listed above may be used for more than one purpose. Statedanother way, wells initially completed for one purpose may later be used for another purpose, PCT/US2008/005056 -23- WO 2008/143749 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 productionwells may also be used as solution production wells for later producing an aqueous solution fromthe organic-rich rock formation.

[0136] 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 productionwells (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 productionwells 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, monitoringwells 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.

[0137] 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 spacedfrom 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 adepth 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.

[0138] It is desirable to arrange the various wells for an oil shale field in a pre-plannedpattern. For instance, heater wells may be arranged in a variety of patterns including, but notlimited 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 pattern PCT/US2008/005056 -24- WO 2008/143749 generally includes a first linear array of heater wells, a second linear array of heater wells, and aproduction 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 be5 similar to or different from that used for the heater wells. (0139] One method to reduce the number of wells is to use a single well as both a heater welland a production well. Reduction of the number of wells by using single wells for sequentialpurposes 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 that10 measure a temperature, a pressure, and/or a property of a fluid in the wellbore, hi someinstances, a heater well may also serve as a monitoring well, or otherwise be instrumented.

[0149] 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 fonn equilateral triangular arrays, hexagonal arrays, or other array patterns. The15 arrays 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.

[0141] 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. 20 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, [0142] 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-spot arrays, with 25 alternating 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. Flow 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. 30 [0143] Figure 4 provides a plan view of an illustrative heater well arrangement using more than 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 heater PCmJS2008/005056 - 25 ־ WO 2008/143749 wells 420. The heater wells in the first layer 410 axe referenced at 431, while the heater wells inthe second layer 420 are referenced at 432.

[0144] 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.

[0145] 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 secondplurality of heater wells 432 comprising a second layer of heater wells 420 placed around the firstlayer 410.

[0146] 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 firstlayer 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.

[0147] Another method for reducing the number of heater wells is to use well patterns thatare elongated in a particular direction, particularly in a direction determined to provide the mostefficient 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 leasthorizontal principal stress.

[0148] 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 andproduction wells. Heterogeneities in the oil shale properties and formation structure may cause PCT/US2008/005056 -26- WO 2008/143749 certain 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 receivemore heat energy than necessary where other regions receive less than desired. This, in turn,leads to the uneven flow and recovery of production fluids. Produced oil quality, overallproduction rate, and/or ultimate recoveries may be reduced.

[0149] 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.

[0150] 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.).

[0151] 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 resistiveheating 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 include PCT/US2008/005056 -27- WO 2008^143749 injecting a hot fluid into the oil shale formation to directly heat it. The hot fluid may or may notbe circulated.

[0152] 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. Theelectric 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 heatershave 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).

[0153] 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 entiredisclosure of this reference is hereby incorporated by reference.

[0154] 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. Thisleads 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.

[0155] As an alternative, international patent publication WO 2005/010320 teaches the use ofelectrically 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 fracturesare 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 the PCT/US2008/005056 ־28* WO 2008/143749 vertical 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 ofelectric heat. Thermal conduction heats the oil shale to conversion temperatures in excess of300° C, causing artificial maturation.

[0156] 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.

[0157] The purpose for heating the organic-rich rock formation is to pyrolyze at least a.portion 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, l’C, 0.5* C, or 0.1* C) per day. In a further embodiment, theportion 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).

[0158] 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. PCTAJS2008/005056 -29- WO 2008/143749 [0159] 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 or, alternatively, 3 to 10 years, 1.5 to 7 years, or 2 to 5 years. The bulk of thetarget zone of the formation may be heated to between 270° to 800° C. Preferably, the bulk of thetarget zone of the formation is heated to between 300° to 600° C. Alternatively, the bulk of thetarget zone is ultimately heated to a temperature below 400° C (752° F).

[0160] 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. 3,109,482; 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. 3,127,936; U.S. Pat. No. 3,095,031;U.S. Pat. No. 5,255,742; and U.S. Pat. No. 5,899,269.

[0161] Downhole burners operate through the transport of a combustible fuel (typicallynatural gas) and an oxidant (typically oxygen-enriched air) to a subsurface position in a wellbore.The fuel and oxidant react downhole to generate heat. The combustion gases are removed(typically by transport to the surface, but possibly via injection into the formation). Downholeburners may utilize pipe-in-pipe arrangements to separately transport fuel and an oxidantdownhole, and then to remove the flue gas back up to the surface. Some downhole burnersgenerate a flame, while others may not.

[0162] 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. The use of downhole burners is also an alternativeto another form of downhole heat generation called steam generation. In downhole steamgeneration, a combustor in the well is used to boil water placed in the wellbore for injection intothe formation. Applications of the downhole heat technology have been described in F.M. Smith,“A Down-hole burner - Versatile tool for well heating,” 25lh Technical Conference on PetroleumProduction, Pennsylvania State University, pp 275285־ (Oct. 19-21, 1966); H. Brandt, W.G.Poynter, and J.D. Hummeil, “Stimulating Heavy Oil Reservoirs with Downhole Air-GasBurners,” World Oil, pp. 9195־ (Sept. 1965); and C.I. DePriester and A.J. Pantaleo, “Well PCT/US2008/005056 -30- WO 2008/143749

Stimulation by Downhole Gas-Air Burner," Journal of Petroleum Technology, pp. 1297-1302(Dec. 1963).

[0163] 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.

[0164] Downhole burners also have advantages over electrical heating methods due to thereduced infrastructure cost. In this respect, there is no need for an expensive electrical powerplant and distribution system. Moreover, there is increased thermal efficiency because theenergy losses inherently experienced during electrical power generation are avoided.

[0165] 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 are preferred.These would include high alumina content ceramics. Other ceramics that may be useful includechrome oxide, zirconia oxide, and magnesium oxide-based ceramics.

[0166] Additionally, the flue gases generated by the downhole burner can be corrosive due toC02 and water content. This is particularly if the water condenses. Use of alloy metals such asstainless steels can be used to reduce this potential problem.

[0167] 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 flame PCT/US2008/005056 -31 - WO 2008/143749 temperatures. 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 exchangecan limit the transport of heat downstream of the burner since the hot flue gases may rapidly loseheat energy to the rising cooler flue gases.

[0168] 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 it across azone of interest One approach to address this issue is to use two or mote smaller burners spacedapart over a desired depth range to provide more uniform heating. In one aspect, a desired lengthof 50 meters, 100 meters, or 200 meters is heated. Another approach is to reduce temperaturesnear the burner so as to avoid excess use of costly refractory materials. Also addressed herein ismaximizing efficiency of heating the target formation by reducing the temperature of the flue gasinitially entering the target formation. .10169] A method for in situ heating of a selected portion of a targeted organic-rich rockformation is provided herein. Preferably, the organic-rich rock formation comprises oil shale. Inone embodiment, the method includes providing casing in a wellbore extending to a depth of theorganic-rich rock formation, and also providing a tubing within the casing. An annular area isdefined between the tubing and the casing. Preferably, the casing is isolated to flow from thesurrounding formation.

[0170] The method also includes the step of injecting air (or other oxidant) and a combustiblefuel into the wellbore. Either the air or the combustible fuel is in stoichiometric combustionexcess over the other. Hardware is provided in the wellbore so as to cause the air and thecombustible fuel to mix and to combust into flue gas at substantially the depth of the targetedportion of the organic-rich rock formation. The hardware includes one or more burners.

[0171] The method further includes moving flue gas up the annular region between thetubing and the surrounding casing. Insulation is provided along the tubing proximate each of theone or more burners. Preferably the insulation is placed below the depth of the shallowestburner. The insulation layer may comprise ceramic. Together with excess gas flow, the.insulation serves to reduce the heat transfer coefficient within the tubing and to provide a moreuniform temperature within the casing along the selected portion of the organic-rich rock PCT/US2008/005056 -32- WO 2008/143749 formation. The uniformity of the temperature profile along the well can be optimized via thechoice of the insulation amount and the amounts of excess air or fuel.

[0172] In one aspect, the temperature along the selected portion of the organic-rich rockformation is between about 300״ C and 900° C. More preferably, the temperature along theselected portion of the organic-rich rock formation is between 300° C and 700° C. Thetemperature of the flue gas may be monitored at a point in the casing, such as near the depth ofthe first burner.

[0173] The first burner may be positioned at any depth within the organic-rich rockformation. For example, the first burner may be placed near the top of the organic-rich rockformation. Alternatively, the first burner may be placed within 50 meters of the top of theorganic-rich rock formation. Alternatively still, the first burner may be placed within 20 metersof the top of the organic-rich rock formation. Preferably, each of the one or more burners iscentralized within the tubing.

[0174] In one embodiment of the methods, the hardware comprises a first tubular memberresiding within the tubing extending to the selected portion of the organic-rich rock formation,and a first burner at a first depth within the organic-rich rock formation. The first burner ispreferably at the lower end of the first tubular member. Preferably, the first tubular memberseparates the air and combustible fuel prior to reaching the first burner. Optionally, the hardwarealso includes a first tubular cowl disposed immediately below the first burner.

[0175] In this embodiment, the hardware also comprises a second tubular member residingwithin the tubing. The second tubular member has a lower end extending to the selected portionof the organic-rich rock formation at a second depth that is lower than the first depth. Thesecond burner is positioned proximate the lower end of the second tubular member. Thehardware may further comprise a second tubular cowl disposed at the lower end of the secondtubular member immediately below the second burner. In one aspect, the first burner and thesecond burner are each separated by about 20 to 150 meters. Alternatively, the first burner andthe second burner are each separated by about 40 to 100 meters.

[0176] The hardware may further comprise a third tubular member residing within thetubing. The third tubular member has a lower end extending to the organic-rich rock formationat a third depth lower than the second depth. The third tubular member also has a third burner atits lower end. A third tubular cowl may be disposed at the lower end of the third tubular memberand immediately below the third burner. In one aspect, the first burner, the second burner, andthe third burner are each separated by about 20 to 60 meters. PCT/US2008/005056 -33- WO 2008/143749 !0177] It is preferred that insulation be placed along the tubing. In one aspect an insulationlayer is placed along the tubing proximate each of the first, second and third burners. In anotheraspect the insulation layer runs the length of the tubing at the depth of the organic-rich rockformation. f0178] In another embodiment, a first burner is positioned along a tubular member at a firstdepth within the selected portion of the organic-rich rock formation, and a second burner ispositioned along the first tubular member at a second depth within the selected portion of theorganic-rich rock formation. The second depth is !«low the first depth. The first and secondburners may be disposed in an annular region defined between the tubular member and thesurrounding tubing.

[0179] A first tubular cowl may be disposed at the first depth immediately below the firstburner. Likewise, a second tubular cowl may be disposed at the second depth immediately belowthe second burner. In one aspect, the first burner and the second burner are each separated withinthe annular region by about 20 to 150 meters.

[01Θ0] In this embodiment, a third burner may be positioned along the first tubular memberand within the annular region at a third depth within the selected portion of the organic-rich rockformation. A third tubular cowl may optionally be disposed at the third depth immediately belowthe third burner. An insulation layer is then placed along an inner surface of the tubingproximate each of the first, second and third burners. In one aspect, the first burner, the secondburner, and the third burner are each separated by about 20 to 100 meters. Alternatively, the firstburner, the second burner, and the third burner are each separated by about 40 to 60 meters.

[0181] In any of these embodiments, a portion of the tubing proximate the first depth ispreferably constructed from an alloy or metal having a higher maximum working temperature ·than a remaining portion of the tubing. The portion of the tubing having a higher maximumworking temperature may, in one aspect, reside proximate the first depth and below, for example,about 10 meters above the first depth, and extend down to about 20 meters below a lowermostburner within the wellbore. Alternately, individual portions of tubing having higher maximumworking temperatures may be located proximate the depth of each respective burner.

[0182] For any of the above-described embodiments, it is desirable to maintain asubstantially uniform temperature profiie along the burners and within the annular area definedbetween the tubing and the surrounding casing. To this end, various parameters may be adjusted.For example, the positions of the burners, the rate of injecting the combustible fuel, the rate ofinjecting the air, or combinations thereof, may be specified so that the temperature of the flue gas PCT/US2OO8/O0SO56 -34- WO 2008/143749 traveling up the annulus is about 300° C to 750° C across the selected portion of the organic-richrock formation. Also, the rate of injecting the combustible fuel may be reduced over time so asto maintain a desired temperature range as the surrounding formation warms.

[0183־] During operation, the flue gas circulated up through the annulus within the casing5 may be collected at the surface. The flue gas may be compressed, and then mixed withcompressed air containing oxygen. This mixture of compressed flue gas and compressed air maybe injected back into the wellbore. Alternatively, the compressed flue gas may be mixed withcombustible gases and then delivered back into the wellbore as combustible fuel.

[0184] In one aspect, returned flue gas is collected at the surface and then monitored for the10 presence of combustible species. The purpose is to assess whether any of the burners are not firing properly. Combustible species may include, for example, methane, ethane, hydrogen (H2),and carbon monoxide.

[0185] In another embodiment, the returned flue gas may be vented to the atmosphere. Inthis instance it is desirable to treat the flue gas to remove NO* components prior to venting the 15 received flue gas.

[0186] The one or more burners may be ignited in various ways. For example, the burnersmay be ignited using electric resistive heating elements. In one aspect, the first burner and thesecond burner are ignited using a removable electrical heating element which can be selectivelyinserted into the first and second tubular members. Alternatively, the burners may be ignited by 20 injecting a pyrophoric substance into the tubular members. The pyrophoric substance may be,for example, liquid triethyl borane.

[0187] For purposes of causing combustion, the hardware may include at least one fuel linefor delivering the injected fuel to the burners. The at least one fuel line may be, for example, asingle fuel line disposed within the annulus outside of the tubing. Alternatively, the at least one 25 fuel line may be a fuel line residing in each of the tubular members.

[0188] The air may be injected into the wellbore in various ways. Excess air may be injectedto reduce, control, and optimize the combustion gas temperature. In one aspect, the air is injectedin excess at a mass rate of 1.25 to 6.0 times the stoichiometric combustion amount.Alternatively, the air may be injected relative to the combustible fuel at 2.0 to 5.0 times 30 stoichiometric. In one embodiment, the air is injected at a rate of about 10,000 to 50,000 kg/day.Alternatively, the air is injected at a rate of about 10,000 to 25,000 kg/day. In one embodiment,the air is injected under a pressure of about 50 to 250 psia. In one embodiment, the burners aresized to deliver 200 to 3,000 watts per meter of formation length desired to be heated. PCT/US2008/005056 ־35־ WO 2008/143749 [0189] The combustible fuel may also be injected into the wellbore in various ways. In oneaspect, the combustible fuel is injected under a pressure of greater than about 200 psia.Alternatively, the combustible fuel is injected under a pressure of greater than about 600 psia.Alternatively still, the combustible fuel may be injected under a pressure of only about 100 to200 psia.

[0190] The method may further comprise the step of heating the oil shale in order to pyrolyzeat least a portion of the oil shale into hydrocarbon fluids. The hydrocarbon fluids will includegas. In this instance, the method will also include producing the gas. The combustible fuel mayat least partially comprise gas produced from the hydrocarbon fluids. In this instance, themethod may further include treating the hydrocarbon fluids and/or the gas in order tosubstantially remove H2S from the gas before re-injecting the gas into the tubular members.

[0191] It is preferred that the heat transfer coefficient between the down-flowing flue gaswithin the tubing and the up-flowing flue gas in the annulus around the tubing be low. In oneaspect, the heat transfer coefficient between the combusted fuel within the tubing and the flue gasin the annulus proximate the burner is less than about 50 W/m2 C and, more preferably is about25 W/m2 C, The insulation helps to reduce the heat transfer coefficient. In one aspect, additionalinsulation is placed inside the tubing within 10 meters before a burner and extending at least 10meters below that burner to reduce the temperature experienced by the metal tubing.

[0192] Also disclosed herein is a heater well for in situ heating of a targeted organic-richrock formation. In one embodiment, the heater well includes a casing in a wellbore extending toa depth of the organic-rich rock formation. Preferably, the casing is substantially sealed to theformation so that fuel and flue gases are substantially isolated from in situ formation fluids. Partof substantially sealing the casing to the formation may include the use of cementing the casingwithin the formation. For example, the casing may be placed in the wellbore with an openbottom. The open bottom may then be sealed to the formation through the placement of cementin the bottom of the wellbore. Alternatively, the bottom of the casing may be capped, forexample by welding a metal plate onto the bottom end at the surface, in order to substantially sealthe casing from the formation.

[0193] A tubing is disposed within the casing. An annulus is thereby formed between thetubing and the surrounding casing. A first tubular member resides within the tubing. The firsttubular member extends to a first depth within the organic-rich rock formation. A first burner isplaced proximate a bottom end of the first tubular member. WO 2008/143749 .35. PCT/US2008/005056 (0194] The heater well also has a second tubular member residing within the tubing. Thesecond tubular member extends to a second depth that is lower than the first depth within theorganic-rich rock formation. A second burner is placed proximate a bottom end of the secondtubular member.

[0195] A first insulation layer is disposed on the tubing proximate the first burner and below.The first insulation layer may be along an outer diameter of the tubing. The first insulation layerserves to reduce the heat transfer coefficient within the tubing. When properly combined withexcess air or fuel flow, this can lead to a more uniform temperature profile in the wellbore.Additional insulation may be disposed proximate each of the first and second burners along aninner diameter of the tubing to protect the metal from extreme temperatures caused by the burnerflames. (0196] In one aspect, a first tubular cowl is disposed immediately below the first burner. Inaddition, a second tubular cowl is disposed immediately below the second burner. The cowlsserve to further reduce the heat transfer coefficient within the tubing by limiting the amount ofheat distributed immediately below the respective burners. (0197] In one aspect, the heater well also has a third tubular member residing within thetubing. The third tubular member extends to a third depth that is lower than the second depthwithin the organic-rich rock formation. A third burner is placed proximate a bottom end of thethird tubular member. An insulation layer may then reside along the tubing proximate the thirdburner.

[0198] Another heater well for in situ heating of an organic-rich rock formation is alsodisclosed herein. In this embodiment, the heater well comprises a casing in a wellbore. Thewellbore extends to a depth of the organic-rich rock formation. Preferably, the casing issubstantially sealed to the formation. A tubing is disposed within the casing. An annulus isthereby formed between the tubing and the surrounding casing. A tubular member resides withinthe tubing and also extends to a first depth within the organic-rich rock formation. An annularregion is thereby also formed between the tubular member and the surrounding tubing.

[0199] A first burner is positioned along the tubular member at a first depth within theselected portion of the organic-rich rock formation. A second burner is also positioned along thefirst tubular member at a second depth within the selected portion of the organic-rich rockformation. The second depth is below the first depth. The first and second burners arepreferably placed within the annular region between the tubular member and the surroundingtubing. PCT/US2008/005056 -37- WO 2008/143749 [0200] A first insulation layer is disposed on an outer diameter of the tubing proximate thefirst burner and below. The first insulation layer serves to reduce the heat transfer coefficientwithin the tubing, which when properly combined with excess air or fuel flow can lead to a moreuniform temperature profile in the wellbore. Additional insulation may be disposed proximateeach of the first and second burners on an inner diameter of the tubing to protect the metal fromextreme temperatures caused by the burner flames.

[0201] In one aspect, a first tubular cowl is disposed immediately below the first burner. Inaddition, a second tubular cowl is disposed immediately below the second burner.

[0202] In one aspect, the heater well also has a third burner positioned along the tubularmember at a third depth within the selected portion of the organic-rich rock formation. The thirddepth is lower than the second depth. An insulation layer resides along the tubing proximate thethird burner.

[0203] Figure 29 provides a cross-sectional view of a heater well 2900, in one embodiment.The heater well 2900 resides within a wellbore 2904 that extends from an earth surface 2902 to atargeted organic-rich rock formation 2905. The organic-rich rock formation 2905 may includetar sands, coal, oil shale, or other rock containing solid hydrocarbons. Preferably, the organic-rich rock formation 2905 is an oil shale containing kerogen that may be pyrolyzed.

[0204] The purpose of the heater well 2900 is to generate heat into the surrounding organic-rich rock formation 2905. More specifically, the heater well 2900 heats the formation 2905 to atemperature that is sufficient to pyrolyze solid hydrocarbons such as kerogen into hytlrocarbonfluids. In the present invention, this is done through the use of combustive heat.

[0205] Air “A” and a combustible fuel “CF’ are injected into the wellbore 2900. The air“A״ and combustible fuel ״CF’ are mixed at a downhole burner 2938, where the fuel combustsand forms a flame. Excess air “A”, if present, and flue gas “FG" flow beyond the burner 2938,down the wellbore 2904, and back up to the surface 2902.

[0206] The wellbore 2904 is cased. A string of casing 2910 is shown extending to a lowerend 2912 of the wellbore 2904. The lower end 2912 of the wellbore 2904 is closed in order tocreate a closed heater well system. Closure may be provided by means of a plate 2913, as shownin Figure 29. Alternatively, closure may be provided through cement injected into the wellbore2904 during completion. The casing 2910 defines a bore 2915 which, as will be discussed PCT/USZ008/0050S6 *38* WO 2008/143749 further below, receives the burner 2938 and other hardware for heating the surrounding organic*rich rock formation 2905, [0207] The heater well 2900 also includes a string of tubing 2920. The tubing 2920 serves asan inner tubing relative to the casing 2910. Thus, a pipe-in-pipe heater arrangement is formed.The tubing 2920 has a lower end 2922 that extends substantially to the lower end 2912 of thewellbore 2904. The lower end 2912 is open. The tubing 2920 and surrounding casing 2910define an annulus 2914 therebetween.

[0208] The burner 2938 in the heater well 2900 preferably comprises a plurality of burners.In the illustrative arrangement of Figure 29, each burner 2938 is disposed at the bottom of atubular member 2930. Three tubular members 2930a, 2930b, 2930c are shown in wellbore 2905,and corresponding burners are indicated as 2938a, 2938b and 2938c. However, it is understoodthat any number of tubular members 2930 and corresponding burners 2938 may be used. Indeed,only one tubular member 2930 and one corresponding burner 2938 may be chosen.

[0209] The tubular members 2938a, 2938b, 2938c are preferably fabricated from stainlesssteel. An annulus 2924 is formed between the tubular members 2930a, 2930b and 2930c and the surrounding tubing 2920.

[0210] Figure 30 provides a top view of the heater well 2900 of Figure 29. Here, the tubing2920 and the surrounding outer casing 2910 are seen. In addition, the three tubular members2930a, 2930b, 2930c are also seen. Centralizers (not shown) may optionally be used to maintainan equidistant spacing of the tubular members 2930a, 2930b, 2930c within a bore 2925 of thetubing 2920.

[0211] Figure 31 shows a side view of one of the burners 2938 disposed at the bottom 2932of a tubular member 2930. Tubular member 2930 is representative of any of tubular members2930a, 2930b or 2930c from the heater well 2900 of Figure 29. It can be seen from both Figure29 and Figure 31 that a cowl 2940 is disposed immediately below the burner 2938. The cowl2940 is preferably fabricated from a heat-resistant material. For example, the cowl 2940 may befabricated from ceramic or a refractory metal or other temperature resistant steel.

[0212] The cowl 2940 is a tubular body having a wall 2942 and a bore 2945 therein. Thewall 2942 has a plurality of perforations or vents 2946 that provide fluid communication betweenthe inner bore 2945 and the surrounding annulus 2924. In the illustrative cowl 2940 of Figure31, flanges 2944 extend outwardly from the wall 2942 to create the vents 2946. The vents 2946 PCT/US2008/005056 -39- WO 2008/143749 receive air, indicated at arrow “A," from the annulus 2924. The air “A,” in turn, mixes withcombustible fuel, shown at arrow “CF," to enable the burner 2938 to create a flame. In additionto aiding mixing, the cowl may serve to prevent excessive radiative heat transfer from the flameto the surrounding tubing 2920. Although not depicted in Figure 31, the arrangement of the air“A” and combustible fuel “CF’ may be reversed such that the vents 294$ receive combustiblefuel “CF’ from the surrounding annulus 2924 which mixes with air “A" from the inner bore2945 to enable the burner 2938 to create a flame.

[0213] Various ways may be provided for igniting the combustible fuel “CF.” For instance,the fuel “CF״ may be ignited using electric resistive heating elements in the tubular members2930. In one aspect, the resistive heating elements are removable electrical heating elementswhich can be selectively inserted into the tubular members 2930. In another aspect, the fuel“CF” and burners 2938 may be ignited by injecting a pyrophoric substance into the tubularmembers 2930. The pyrophoric substance may be either a liquid or a solid substance.

[0214] Igniting a burner 2938 creates a flame. Those of ordinary skill in the art willappreciate that the flame generated from a downhole burner, such as burners 2938a, 2938b and2938c generates a flame that is extremely hot. In one aspect, the flame and the circulation of fluegas "FG” through the heater well 2900 causes the targeted organic-rich rock formation 2905 to 'be heated to between about 300° C and 700° C. The use of such a downhole burner 2938 createsa point of very high heat which diminishes as the flue gas “FG” is circulated through the heater,well 2900. The use of cowls 2940 helps to contain radiant heat and to cool the hot flue gases“FG" with air “A.” In this way, only the cowl 2940 and perhaps a relatively short length of thesurrounding tubing 2920 needs to be constructed from special temperature-resistant materials.The cowls 2940 employ an elongated body 2942 which insulates the surrounding tubing 2920from immediate contact with the flames. The elongated body 2942 also provides for a moreuniform heat distribution from the flames to the surrounding tubing 2920 and, ultimately, theorganic-rich rock formation 2905.

[0215] Additional approaches may be taken to provide for a more uniform heat distributionfrom the flames to the surrounding tubing 2920 and, ultimately, the organic-rich rock formation2905. In one aspect, the volume of air “A" injected into the wellbore 2925 may be increased.For example, the air “A” may be injected at about 1.25 to 6.0 or, more preferably, 2.0 to 5.0times the stoichiometric combustion amount. Alternatively, or in addition, an insulative layermay be placed along the tubing 2920 at and below the level of the uppermost burner 2938a, thatis, the burner disposed at the bottom of tubular member 2930a. PCT/US2008/005056 ־40* WO 2008/143749 (0216) Returning to Figure 29, it can be seen that various items of surface equipment areshown. First, a compressor 2954 is seen. The compressor 2954 receives air ״A” from an intakeline 2952. The compressor 2954 pressurizes the air “A” and then delivers it to the tubing 2920via line 2956. Once again, arrow "A” demonstrates the injection of air into the tubing 2920.More specifically, in the illustrative wellbore 2925 air “A” is injected into the annulus 2924 ofthe tubing 2920. !0217) The surface equipment also includes a fuel tank 2964. The fuel tank 2964 storescombustible fuel “CF’ that is injected into the tubular members 2930a, 2930b, and 2930c. Fuelmay be fed into the fuel tank 2964 through an input line 2966. Fuel may be gaseous or liquid.Alternatively, the tank 2964 may be periodically refilled from a delivery truck or other source.The combustible fuel ,‘CF’ is injected into the tubular members 2930a, 2930b, and 2930c via aninjection line 2962. The injection line 2962 may be manifolded as shown in Figure 29 to altow asingle line to feed fuel "CF” into all of the tubular members 2930a, 2930b, and 2930c. It isunderstood that a fuel line (not shown) may also be used to deliver fuel UCF’ immediately to therespective burners 2938a, 2938b, 2938c downhole. Such fuel lines may reside in each of the first2930a, second 2930b and third 2930c tubulars. (0218) In order to create the heat-generating flames from the burners 2938a, 2938b, 2938c,combustible fuel "CF* is injected into the respective tubular members 2930a, 2930b, and 2930cunder pressure. In one aspect, the combustible fuel “CF” is injected under a pressure of greaterthan about 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 100 to 200 psia.

[0218] It is seen in Figure 29 that the downhole burners 2938a, 2938b, and 2938c arepositioned at varying depths. The purpose is to create a series of staged heat sources at differentlevels or depths within the targeted formation 2905. Stated another way, flue gas “FG” isgenerated at different intervals along the wellbore 2900 to create a more uniform thermalconvection profile away from the heater well 2900 and into the formation 2905.

[0220] Figure 29 indicates arrows “FG” demonstrating the flow of heated flue gases downfrom each burner 2938a, 2938b, 2938c. The flue gas “FG” is circulated to the lower end 2912 ofthe casing 2910 and into the annulus 2914 around the tubing 2920. The flue gas “FG” thenmoves up the annulus 2914 where it carries hot flue gas “FG” to warm the casing 2910 and thesurrounding formation 2905. PCT/US2008/005056 -41 - WO 2008/143749 [0221] A heat transfer coefficient exists between the downward-flowing air “A” within thetubing 2920 and the upward-flowing flue gas “FG” in the annulus 2914. In one aspect, the heattransfer coefficient is greater than about 75 W/m2 C above the top burner location. Morepreferably, the heat transfer coefficient between the air “A" within the tubing 2920 and the fluegas “FG” in the annulus 2914 is greater than about 150 W/m2C above about the top burnerlocation.

[0222] A heat transfer coefficient also exists between the downflowing flue gas “FG” withinthe tubing 2920 and the upflowing flue gas “FG” in the annulus 2914. In one aspect, the heattransfer coefficient is between about 10 and 40 W/m2 C below about the top burner 2938alocation. More preferably, the heat transfer coefficient between the downflowing flue gas “FG"within the tubing 2920 and the upflowing flue gas “FG” in the annulus 2914 is between about 10to 30 W/m2 C below the depth of the top burner 2938a.

[0223] The flue gas “FG” is circulated to the surface 2902. Once at the surface 2902, theflue gas “FG" may be vented to the atmosphere. In this instance, the flue gas “FG” is preferablytreated to reduce NOx components prior to venting. Alternatively if the flue gas “FG” still hassignificant oxygen content or significant fuel content, the flue gas “FG” may be redirected to beused as an oxidant or fuel supply for another well or surface combustor.. Figure 29 shows theflue gas “FG” being captured by line 2972, and then being delivered to a separator 2974. Theseparator 2974 is preferably a scrubber used to remove potential pollutants comprising, NOx,SOj, or particulates from the flue gas “FG.” [0224] In one aspect (not shown), the collected flue gas “FG” is compressed. The flue gas"FG" containing oxygen, preferably &gt;10 mol%, may then be mixed with compressed air. Themixture is then delivered back into the annulus 2924 together as air “A." Recapturing the fluegas “FG” allows the step of injecting the air “A” to use the pressure from the flue gas “FG,”thereby reducing compression needs at the heater well 2900. In other words, the size or capacityof compressor 2954 is reduced.

[0225] In another aspect shown in Figure 29, the collected flue gas “FG” is compressed.The flue gas “FG” containing combustible gases, preferably &gt;25 mol%, “FG” may then bemixed with compressed fuel. The mixture is then delivered back into the tubular members2930a, 2930b, and 2930c together as combustible fuel “CF.” The combustible fuel “CF’ maycomprise, for example, methane, ethane or mixtures of combustible gas species. PCT/US2008/005056 -42- WO 2008/143749 [0226] In another aspect, the flue gas “FG" is again collected from the heater well 2900 atthe surface 2902. The flue gas “FG” may then be monitored for the presence of combustiblespecies to assess whether the burners 2938 are firing properly. The combustible species maycomprise at least one of methane, ethane, hydrogen (¾), and carbon monoxide.

[0227] As noted, the tubing 2920 is preferably insulated at depths adjacent and immediatelybelow the respective burners 2938a, 2938b, and 2938c. Such insulation is preferably along theouter diameter of the tubing 2920. For example, insulation may be provided by cladding orbonding a ceramic material to the tubing 2920. Such an insulative layer is shown in Figure 29 at2918.

[0228] The insulative layer 2918 moderates the heat transfer coefficient between thedownflow of flue gas “FG” within the tubing 2920 and the upward flow of flue gas “FG" in theannulus 2914. In this respect, hot flue gas “FG” moving downward within the tubing 2920 canexperience heat transfer with flue gas “FG” moving upward in the annulus 2914. This isparticularly beneficial at points immediately below the burners 2938a, 2938b, and 2938c. High!heat transfer at depths below the burners 2938a, 2938b, and 2938c leads to a short zone ofheating around the wellbore 2904 since the downflowing hot gas “FG” within the pipes 2930a,2930b, and 2930c quickly loses heat to the upgoing cooler flue gas “FG” in the annulus 2924.On the other hand, a very low heat transfer coefficient below the burners 2938a, 2938b, and2938c leads to little heat loss from the downflowing hot gases “FG,” leading to unnecessarilyhigh temperatures in the upgoing flue gas “FG” used to heat the formation 2905.

[0229] To moderately reduce the heat transfer coefficient and to create a more uniform heatprofile away from the wellbore 2900 in the organic-rich formation 2905, the insulative layer2918 is provided. In one aspect, the heat transfer coefficient is reduced by a factor of at least twocompared to uninsulated regions within the wellbore 2904 or as compared to the heat transfercoefficient without an insulative layer 2918. More preferably, the heat transfer reduction isreduced by a factor of at least four.

[0230] As noted, heat transfer may also occur between the downflowing air “A” in the tubingannulus 2924 and the upflowing flue gas “FG” in the casing annulus 2914. In this respect, the air"A” moving downward within the tubing 2920 can experience heat transfer with the hot fluegases “FG” moving upward in the annulus 2914. The potential for this heat transfer isparticularly high immediately above the burners 2938a, 2938b, 2938c. The insulative layer 2918again assists in limiting this heat transfer. WO 2008/143749 .43. PCT/US2008/005056 [0231] To address these issues, and in addition to providing the insulative layer 2918, excessair “A” may be injected into the wellbore 2900. Alternatively, or in addition, excess fuel “CF1may be injected into the wellbore 2900. The use of excess gases and the use of insulatingcladding, particularly in combination, can lead to a more uniform temperature profile below the 5 burner 2938.

[0232] When excess fuel “CF’ is used, it may be desirable to switch the air “A” and fuel“CF’ flow paths so that the air “A” will flow through the inner tubular members 2930a, 2930b,2930c and fuel "CF’ through the annulus region 2924. A flame generated by this method is aso-called "reverse diffusion” flame and can lead to lower NOx generation in certain cases. 10 [0233] Using a heater well such as heater well 2900, a method for in situ heating of a targeted organic-rich rock formation is provided herein. In one aspect, the method includes the steps ofproviding casing 2910 in a wellbore 2904 extending to a depth of the organic-rich rock formation2905. The casing 2910 preferably has a closed lower end 2912. A tubing 2920 is providedwithin the casing 2910. The tubing 2920 defines an annulus 2914 between the tubing 2920 and15 the surrounding casing 2910. The method further includes injecting air and a combustible fuelinto the tubing 2920, and providing hardware in the tubing 2920 so as to cause the air and thecombustible fuel to mix at substantially the depth of the organic-rich rock formation 2905 and insuch a manner that a thermal conduction profile adjacent the wellbore 2904 along a selectedportion of the organic-rich rock formation 2905 is substantially uniform. Preferably, the20 temperature profile in the annular region adjacent the selected portion of the organic-rich rockformation 2905 remains relatively uniform at a temperature between about 300° C and 900° C.More preferably, the temperature profile along the wellbore 2900 into the formation 2905remains fairly uniform between about 300" C and 750° C.

[0234] In one embodiment, the hardware comprises a first tubular member 2930a residing25 within the tubing 2920 extending to the selected portion of the organic-rich rock formation 2905,and a first burner 2938a at a first depth within the organic-rich rock formation 2905. The firstburner 2938a is preferably at the lower end of the first tubular member 2930a. Preferably, thefirst tubular member 2930a separates the air and combustible fuel prior to reaching the firstburner 2938a. Optionally, the hardware also includes a first tubular cowl 2940 disposed30 immediately below the first burner 2938a

<img img-format="tif" img-content="drawing" file="IL200834AD00451.tif" id="idf0006" />

i [0235] The hardware also comprises a second tubular member 2930b residing within thetubing 2920. The second tubular member 2930b has a lower end extending to the selected PCT/US2008/005056 -44- WO 2008/143749 portion of the organic-rich rock formation 2905 at a second depth that is lower than the firstdepth. A second burner 2938b is positioned proximate the lower end of the second tubularmember 2930b. The hardware may further comprise a second tubular cowl 2940 disposed at thelower end of the second tubular member 2930b immediately below the second burner 2938b. Inone aspect, the first burner 2938a and the second burner 2938b are each separated by about 20 to150 meters. Alternatively, the first burner 2938a and the second burner 2938b are each separatedby about 40 to 100 meters.

[0236] The hardware also preferably comprises an insulation layer 2918 placed along aninner surface of the tubing 2920 proximate at least the first 2938a and second 2938b burners. Inanother aspect, the insulation layer 2918 runs the length of the tubing 2920 at the depth of theorganic-rich rock formation 2905.

[0237] The hardware may further comprise a third tubular member 2930c residing within thetubing 2920. The third tubular member 2930c has a lower end extending to the organic-rich rockformation 2905 at a third depth lower than the second depth. The third tubular member 2930calso has a third burner 2938c at its lower end. A third tubular cowl 2940 is disposed at the lowerend of the third tubular member 2930c and immediately below the third burner 2938c.

[0238] In one aspect, the first burner 2938a, the second burner 2938b, and the third burner2938c are each separated by about 20 to 200 meters. Alternatively, the first burner, the secondburner, and the third burner are each separated by about 40 to 150 meters, or by 60 to 120 meters.

[0239] Yet another embodiment for a heater well employing downhole burners is providedherein. Figure 32 presents a cross-sectional view of a heater well 3200 in yet an additionalalternate embodiment. The heater well 3200 is disposed in a wellbore 2904 that is completedthrough an organic-rich rock formation 2905. Preferably, the organic-rich rock formation 2905comprises oil shale, kerogen, or other solid hydrocarbons that may be pyrolyzed. A plurality ofburners 3238a, 3238b, and 3238c is again disposed in the heater well 3200 in order to generateheat needed for pyrolysis.

[0240] It is noticed in connection with Figure 32 that like numbers from Figure 29 are usedto describe like features in Figure 32. Thus, for example, the wellbore 2904 is cased with astring of casing 2910 that extends down to a lower end 2912 of the wellbore 2904. The lowerend 2912 of the wellbore 2904 is again closed in order to create a closed heater well system.Closure may be provided by means of a plate 2913, as shown in Figure 32. Alternatively,closure may be provided through cement injected into the wellbore 2904 during completion. The PCT/U S2008/005056 -45- WO 2008/143749 casing 2910 once again defines a bore 2915 which receives hardware for heating the surroundingorganic-rich rock formation 2905.

[0241] The heater well 3200 also includes a string of tubing 2920. The tubing 2920 serves asan inner tubing relative to the casing 2910. Thus, a pipe-in-pipe heater arrangement is once againformed. The tubing 2920 has a lower end 2922 that extends substantially to the lower end 2912of the wellbore 2904. The lower end 2912 is open. The tubing 2920 and surrounding casing2910 define an annulus 2914 there between.

[0242] The heater well 3200 also comprises a plurality of burners 3238a, 3238b, 3238c. Inthe illustrative arrangement of Figure 32, three burners 3238a, 3238b, 3238c are disposed alonga first or central tubular member 3230. However, it is understood that any number of burnersmay be used in the heater well 3200.

[0243] The central tubular member 3230 is disposed within the tubing 2920. One or morecentralizers 3237 may be used to secure the central tubular member 3230 within the tubing 2920.The centralizers 3237 also secure the position of the burners 3238a, 3238b, and 3238c within thewellbore 2904. An annulus 2924 is formed between the central tubular member 3230 and thesurrounding tubing 2920. In the illustrative heater well 3200, the burners 3238a, 3238b, and3238c reside within the annulus 2924.

[0244] Figure 33 provides a side view of one of the burners 3238 from the heater well 3200of Figure 32. A cowl 3240 is seen disposed immediately below the burner 3238. As with cowl2940 of Figure 31, cowl 3240 is a tubular body having a wall 3242 and a bore 3245 therein. Thewall 3242 has a plurality of perforations or vents 3246 that provide fluid communication betweenthe inner bore 3245 and the surrounding annulus 2924. In the illustrative cowl 3240 of Figure33, flanges 3244 extend outwardly from the wall 3242 to create the vents 3246. The vents 3246receive air, indicated at arrows “A,” from the annulus 2924. The air “A,” in turn, mixes withcombustible fuel, shown at arrow “CF,” to enable the burner 3238 to create a flame.

[0245] Various ways may be provided for igniting the combustible fuel “CF." For instance,the fuel “CF’ may be ignited using electric resistive heating elements in the tubular member3230. In one aspect, the resistive heating elements are removable electrical heating elementswhich can be selectively inserted into the tubular member 3230. In another aspect, the fuel “CF*and burners 3238 may be ignited by injecting a pyrophoric substance into the central tubularmember 3230. An example of a suitable pyrophoric substance is triethylborane. PCT/US2008/005056 -46- WO 2008/143749 [0246] In the burner arrangement of Figure 33, the burners 3238a, 3238b, 3238c extendoutward from the central tubular member 3230. Each of the burners 3238a, 3238b, 3238cincludes a flow branch 3243 which provides fluid communication between the various burners3238a, 3238b, 3238c and a central bore 3235 in the tubular member 3230. A distal end 3247 ofthe flow branch 3243 connects to the central tubular member 3230.

[0247] A plate 3241 is provided at the top of the cowl 3240. The flow branch 3243 isreceived through the plate 3241. The burner 3238 is disposed below the plate 3241 and withinthe cowl 3240. As noted above in connection with Figure 31, the cowl 3240 provides severalfunctions which help provide a more uniform heat distribution across the targeted area within theformation 2905. The elongated body 3242 of the cowl 3240 insulates the surrounding tubing2920 from immediate contact with the flame. In one aspect, the cowls 3240 are fabricated fromceramic or a refractory metal. Still further, the vents 3246 in the cowl 3240 receive air “A" alongits length so as to cool the region immediately.around the cowl 3240 to prevent a hot spot.

[0248] Additional approaches may be taken to provide for a more uniform heat distributionfrom the flames to the surrounding tubing 2920 and, ultimately, the organic-rich rock formation2905. In one aspect, the volume of air “A” injected into the annulus 2924 may again beincreased. For example, the air “A" may be injected at about two to five stoichometric.Alternatively, or in addition, an insulative layer may be placed along the tubing 2920 at andbelow the level of the uppermost burner 3238a.

[0249] Returning to Figure 32, it can be seen that the various downhole burners 3238a,3238b, and 3238c are positioned at varying depths. The purpose is to create a series of stagedheat sources at different levels or depths within the targeted formation 2905. This further servesto create a more uniform thermal conduction profile away from the wellbore 2904 and into theformation 2905. Figure 32 indicates arrows “FG” demonstrating the flow of heated flue gasdown from each burner 3238.

[0250] It is also seen in Figure 32 that various items of surface equipment are shown. Thesurface equipment is essentially the same as that described in connection with the heater well2900 of Figure 29. This equipment includes, for example the air compressor 2954 forcompressing air “A,” and the fuel tank 2964 for storing combustible fuel “CF.” [0251] In operation, air “A” is circulated through the bore 2925 of the tubing 2920. In oneaspect, the air “A” is injected in excess at a mass rate of 1.25 to 2.5 times the stoichometric airrequirement. In one aspect, the total injected gas rate, i.e., air “A” and fuel “CF,” is about 10,000 PCT/US2008/005056 ־47־ WO 2008/143749 to 75,000 kg/day. More preferably, the injected gas rate is about 30,000 to 60,000 kg/day. Inone aspect, the air “A” is injected under a pressure of about 50 to 250 psia. These injectionvalues may be applied in connection with the heater well 2900 in Figure 29 as well.

[0252} Circulating the air “A” under pressure carries heated flue gas “FG” towards the lower5 end 2912 of the casing 2910. The flue gas “FG" is circulated into the annulus 2914 around thetubing 2920. The flue gas “FG” then moves up the annulus 2914 where it carries hot flue gas“FG” to warm the casing 2910 and surrounding formation 2905.

[0253] Experiments to obtain a more uniform heat distribution in a downhole combustionheater well are demonstrated in Figures 34A, 34B, 34C and 34D. These Figures represent heat 10 transfer simulations in different wellbore arrangements. In each wellbore, an inner tubing and anouter tubing are assumed for a pipe-in־pipe arrangement. The inner tubing may be tubing 2920as shown in Figure 29 or Figure 32, while the outer tubing may be, for example, casing 2910.

[0254] Before discussing the charts of Figures 34A, 34B, 34C and 34D, it is beneficial toreview Figure 35. Figure 35 provides a cross-sectional side view of a downhole burner 15 arrangement 3500 assumed in the simulations of Figure 34A and in accordance with certainaspects of the present inventions. The downhole burner 3500 is disposed within a string ofcasing 3510. The casing 3510 is preferably capped at a lower end 3514. A cap 3516 is shown inFigure 35.

[0255] The downhole burner 3500 also has an inner tubing 3520. The tubing 3520 is20 disposed centrally within the casing 3510. Centralizers 3512 are optionally used to hold the tubing 3520 within the casing 3510. Insulation 3518 is placed along the tubing 3520. In oneaspect, the insulation 3518 provides a heat transfer coefficient of 22 W/m2 °C.

[0255] In the wellbore 3500, a downhole burner 3538 is provided. A single burner 3538 isillustrated. The insulation 3518 is placed along an outer diameter of the tubing 3520 adjacent25 and below the burner 3538. The burner 3538 is a 329 kW burner.

[0257] The burner 3538 is ran into and resides within the tubing 3520 at the end of a pipe3530. The pipe 3530 is an elongated tubular member and receives combustible fuel “CF.” Acowl 3540 is preferably placed at the end of the pipe 3530 adjacent or below the burner 3538.The pipe 3530 is optionally centralized within the tubing 3520 using centralizers 3522. PCT/US2008/005056 ־48- WO 2008/143749 [0258] An additional layer of insulation 3528 is optionally added along the tubing 3520.This additional insulation 3528 is disposed immediately along or below the burner 3538.Preferably, the additional insulation is along an inner diameter of the tubing 3520. In one aspect,the insulation 3528 begins about 10 meters above the burner 3538, and extends about 20 metersbelow the burner 3538. Alternatively, the tubing 3520 along this area of the wellbore 3500 isfabricated from ceramic or other highly heat-resistant material.

[0259} An annulus 3515 is formed between the tubing 3520 and the surrounding casing 3530.The annulus 3515 receives air “A.” The air “A” and the combustible fuel “CF’ mix at the levelof the burner 3538 and ignite, forming a flame 3560.

[0260] Referring again now to the simulation charts, Figure 34A is a graph charting depth ina wellbore (such as wellbore 2900) versus temperature. The depth in the wellbore is chartedrelative to the location of the burner downhole. In this simulation, a single 329 kW burner wasassumed. The burner is located at the zero position on the x־axis.

[0261] The wellbore is assumed to be insulated adjacent the burner 3538 such as by usinginsulation 3518. The overall heat transfer coefficient between the downward air “A” flow andthe upward flue gas “FG” flow was U=180 W/m2C above the burner 3538. This is the assumedarea without insulation. Below the burner 3538, the heat transfer coefficient was only U-22W/m2 C. This indicates a much lower heat transfer in the region around the assumed insulationlayer.

[0262] . To aid in the movement of heat from inside of the tubing 3520 to outside of the tubing3520, a high flow rate of air “A” was assumed in the calculations. A total gas rate of 50,000kg/day was modeled, representing 5.4 times the stoichiometric amount of air need to combustmethane fuel.

[0263] Those of ordinary skill in the art will appreciate that the stoichiometric amount ofoxygen needed to bum methane (assumed as the combustible fuel “CF’) is: CHt+202-*C02+2H20.

[0264] Air is only 21 mol% oxygen. Thus, 9.5 moles of air are needed per mole of C//4,which is equal to 17.3 kg of air per 1 kg CH4. (Note that air is 29 grams/mol while C7/4 is 16grams/mol). Thus, for example, 50,000 kg/day of air at 4 times the stoichiometric implies about723 kg/day of injected methane fuel. PCTYUS2008/005056 49· WO 2008/143749 [0265] In Figure 34A, the average temperatures inside of the tubing 3520 and outside of thetubing 3520 in the annulus 3515 are compared. More specifically, temperatures were comparedbetween the downward air flow “A״ and the upward flow of flue gas “FG.” It is noted that it isthe temperature in the annular region 3515 (i.e., the outer temperature) that distributes or controlsthe temperature in the adjacent formation.

[0266] As illustrated, the temperature inside of the tubing 3520 reached approximately 825°C at the depth of the burner 3538, but tapered to approximately 450® C at 150 meters below theburner 3538. However, the temperature outside of the tubing 3520 reached only about 450 °C atthe depth of the burner 3538, but then remained relatively stable within the wellbore below theburner 3538. The temperature outside the tubing 3520 only dropped approximately 75° C beforereturning to approximately the same temperature of about 450° C at 150 meters below the burner3538. Thus, the temperature of the casing 3510 immediately adjacent the surrounding formationremained substantially uniform, thereby minimizing the “hot spot” effect normally seen indownhole burner applications.

[0267] Figure 34B is another graph charting depth in a wellbore versus temperature. Thedepth in the wellbore is charted relative to the location of a burner downhole. In this wellbore, asingle burner was used, but no insulation was provided along the inner tubing 3520. Because noinsulation is used, the heat transfer coefficient is constant above and below the burner 3538. Theheat transfer through the inner tubing 3520 is assumed to have a heat transfer coefficient of about180 W/m2 °C along the relevant length.

[0268] To aid in the movement of heat from inside of the inner tubing 3520 to outside of theinner tubing 3520, the flow rate of air “A” was increased to above stoichiometric. This caseagain modeled 50,000 kg/day total gas representing 5.4 times the stoichiometric amount of airneeded to combust methane fuel.

[0269] As illustrated, the temperature of the inner tubing 3520 rose above 1,000 °C at thedepth of the burner, and then dropped to approximately 100״ C at a depth 150 meters below theburner. Similarly, the outer tubing 3510 reached 900° C near the burner, and then dropped non-linearly to approximately 100° C at 150 meters below the burner. The extreme temperatureprofile confirms the utility of insulation around the inner tubing 3520.

[0270] Figure 34C is another graph charting depth in a wellbore versus temperature. Thedepth in the wellbore is again charted relative to the location of a burner downhole. In thiswellbore, a single 320 kW burner is assumed. Insulation 3518 is once again placed along the PCT/US2008/0050S6 -50- WO 2008/143749 inner tubing 3520 below the burner 3538 as in the simulation of Figure 34A. The overall heattransfer coefficient between the downward air “A” flow and the upward flue gas “FG” flow wasU=180 W/m2C above the burner 3538. Below the burner 3538, the heat transfer coefficient wasU-22 W/m2 C. This indicates a much lower heat transfer in the region around the assumedinsulation layer.

[0271] To aid in the movement of heat from inside of the inner tubing 3520 to outside of theinner tubing 3520, the flow rate of air was increased over the stoichiometric need, but not asmuch as in the simulations of Figures 34A and 34B. In the simulation of Figure 34C, the totalgas was injected at 20,000 kg/day. This represents 2.1 times the stoichiometric amount of airneeded to combust methane fuel.

[0272] As illustrated, the temperature of the inner tubing 3520 rose above 1,000 °C aroundthe burner 3538 and steadily dropped to approximately 250° C at 150 meters below the burner3538. Similarly, the outer tubing 3510 reached 900° C nearest the burner 3538, and then droppednon-linearly to approximately 250° C at 150 meters below the burner 3538. The extremetemperature swings in Figure 34C illustrate the preference for extra air flow to achieve optimaltemperature maintenance throughout the wellbore.

[0273] Figure 34D provides yet another graph charting depth in a wellbore versustemperature. Once again, the average temperatures inside and outside of the tubing 3520 arecompared. More specifically, temperatures are compared between the downward air flow “A”and the upward flow of flue gas “FG.” [0274] The depth in die wellbore is charted relative to the location of a burner downhole. Inthis wellbore, three burners are placed approximately 100 meters apart. Each burner was a 170kW burner. This is a smaller burner than was used in the single burner simulations of Figures34A, 34B, and 34C.

[0275] Insulation 3518 is assumed to be placed along the inner tubing 3520 below theuppermost burner. The insulation is assumed to be along the entire length of the tubing along thesubsurface formation, and provides a heat transfer coefficient of 25 W/m2 °C. In areas along thetubing 3520 where there is no insulation, the overall heat transfer coefficient between thedownward air “A” flow and the upward flue gas “FG” flow was 180 W/m2C. PCT/US2008/0050S6 -51- WO 2008/143749 [0276] To aid in the movement of heat from inside of the inner tubing 3520 to outside of theinner tubing 3520, the flow rate of air was increased. The total gas was injected at 40,000kg/day. This represents 2.7 times the stoichiometric amount of air to combust methane fuel [0277] As illustrated in Figure 34D, the temperature of the inner tubing 3520 rose toapproximately 650° C at the depth of the first burner, and then quickly dropped to approximately400° C at a depth of 100 meters below the first burner. When the air hit the second burner, thetemperature inside of the inner tubing 2920 again increased to just over 700° C. The temperaturewithin the inner tubing 2920 decreased again to about 400° C at a further depth of 100 metersbelow the second burner. This pattern was repeated at the third burner, with the inner tubing2920 reaching just over 700° C at the third burner and then dropping to about 400° C at a furtherdepth of 100 meters below the third burner. ..

[0276] Concerning the outer tubing 3510, the outer tubing 3510 reached a temperature ofapproximately 425° C at the depth of the first burner, and then dropped to approximately 350° C50 meters below the first burner. Of interest, the temperature in the outer tubing 3510 then beganto rise again until reaching an approximate temperature of 475° C near the second burner. Thetemperature again dropped to about 350° C before rising again to about 475° C at the depth of thethird burner.

[0279] The chart of Figure 34D demonstrates that the use of multiple smaller burners withina heater well helps to maintain a relatively constant temperature within the piping 2910 adjacentthe surrounding formation. Smaller burners means burners that are rated to have a lower power,that is, a lower energy output per unit of time, e.g., Watts or BTU/hour. The temperature in thecasing 3510 (outside of the tubing 3520) stayed within a range of 350° C to about 475° C over adepth of 300 meters. This temperature range is above the temperature generally needed for thepyrolysis of oil shale. Along with Figure 34B, Figure 34D also demonstrates the efficacy ofinsulation along the tubing 3520 in providing a more uniform heat profile.

[0260] Using a heater well such as heater well 3200, a method for in situ heating of a targetedorganic-rich rock formation is again provided herein. In one aspect, the method includes thesteps of providing casing 2910 in a wellbore 2904 extending to a depth of the organic-rich rockformation 2905. The casing has a closed lower end 2912. A tubing 2920 is provided within thecasing 2910. The tubing 2920 defines an annulus 2914 between the tubing 2920 and thesurrounding casing 2910. The method further includes injecting air and a combustible fuel intothe tubing 2920, and providing hardware in the tubing 2920 so as to cause the air and the PCT/US2008/005056 -52- WO 2008/143749 combustible fuel to mix at substantially the depth of the organic-rich rock formation 2905 and insuch a manner that a thermal conduction profile adjacent the wellbore 2904 along a selectedportion of the organic-rich rock formation 2905 is substantially uniform. Preferably, the thermalconduction profile adjacent the wellbore 2904 along the selected portion of the organic-rich rockformation 2905 remains uniformly between about 300° C and 750° C.

[0281! In one embodiment, such as the embodiment shown in Figure 32, the hardwarecomprises a first tubular member 3230 residing within the tubing 2920 and extending to theselected portion of the organic-rich rock formation 2905. A first burner 3238a is located at a firstdepth within the organic-rich rock formation 2905, and a second burner 3238b is located at asecond depth within the organic-rich rock formation 2905 that is lower than the first depth. Eachburner 3238a, 3238b (and any others) are positioned along the first tubular member 3230.Preferably, the hardware further includes a first tubular cowl 3240 disposed around orimmediately below the first burner 3238a, and a second tubular cowl 3240 disposed around orimmediately below the second burner 3238b. The hardware also preferably comprises aninsulation layer placed along an inner surface of the tubing 2920 proximate the first 3238a andsecond 3238b burners.

[0282] As shown in Figure 32, the hardware in the heater well 3200 may also comprise athird burner 3238c. A tubular cowl 3240 is also disposed around this burner 3238c. In oneaspect, the first burner 3238a, the second burner 3238b, and the third burner 3238c are eachseparated by about 20 to 200 meters. Alternatively, the first burner, the second burner, and thethird burner are each separated by about 20 to 200 meters. Alternatively, the first burner 3238a,the second burner 3238b, and the third burner 3238c are each separated by about 40 to 150meters, or by 60 to 120 meters.

[0283] Various size burners may be employed in the heater well 3200. For example, theburners may each supply about 0.5 to 4.0 kW of thermal energy per meter of formation to beheated or, alternatively, 1 to 3 kW/m. In one aspect, the burners each have an expander (notshown) below the orifice to reduce flow velocity of the combustible fuel “CF’ prior tocombustion.

[0284] In one embodiment, a portion of the tubing 2920 proximate the first depth isconstructed from an alloy or metal having a higher maximum working temperature than aremaining portion of the tubing. In one aspect, the portion of the tubing having a higher PCT/US2008/005056 -53- WO 2008/143749 maximum working temperature resides about 10 meters above the depth of a burner, and extendsdown to about 20 meters below the burner within the tubing 2920.

[0285] In one embodiment, the method further includes the step of directing “FG” generatedfrom the first burner 3238a and at least the second burner 3238b up into the annulus 2924. Inthis embodiment, the method may also include monitoring a temperature of the flue gas “FG” ata point in the casing 2910 near the depth of the first burner 3238a.

[0286] It is desirable to control the heat conducted into the formation 2905. Thus, in oneembodiment the positions of the burners, the rate of injecting the combustible fuel, the rate ofinjecting the air, or combinations thereof, are specified so that the temperature of the flue gas“FG" traveling up the annulus 2924 is about 300° C to 900° C across a majority of the organic-rich rock formation 2905. More preferably, the temperature profile along the wellbore 2900 or3200 into the formation 2905 remains fairly uniform between about 300° C and 750° C. The rateof injecting the combustible fuel may be reduced over time to control the temperature as theformation warms.

[0287] In one embodiment, the combustible fuel is a fuel gas such as natural gas. Theintensity of the burners 3238 is then controlled by adjusting the composition of the fuel gas. Forinstance, the natural gas may be diluted with added inert components. The added inertcomponents may comprise at least one of carbon dioxide (C02) or nitrogen (N2). Reducing flameintensity can lead to reduced NOx generation.

[0288] The position of the uppermost burner 3238a may also be adjusted. In one aspect, thefirst burner 3238a is placed near the top of the targeted section of an organic-rich rock formation2905. In another aspect, the first burner 3238a is placed within 50 meters of the top of thetargeted section of an organic-rich rock formation 2905, Alternatively still, the First burner3238a is placed within 20 meters of the top of the targeted section of an organic-rich rockformation 2905.

[0269] Various means may be used for injecting the combustible fuel into the first tubularmember. In one aspect, the hardware further comprises at least one fuel line for delivering theinjected fuel to the burners 3238. The at least one fuel line may comprise a single fuel linedisposed primarily within the annulus 2924.

[0290] In one embodiment, the method further includes heating the oil shale in order topyrolyze at least a portion of the oil shale into hydrocarbon fluids, the hydrocarbon fluids PCT/US2OO8/0O5O56 -54 WO 2008/143749 comprising gas, and producing the gas. In this embodiment, the combustible fuel may comprisethe gas produced from the hydrocarbon fluids. This method may further include treating thehydrocarbon fluids in order to substantially remove H2S from the gas before re-injecting the gasinto the tubular member.

[0291] In one aspect, the positions of the burners, the rate of injecting the combustible fuel,the rate of injecting the air, or combinations thereof, are specified so that the temperature of theflue gas traveling up the annulus is about 300° C to 750° C across the selected portion of theorganic-rich rock formation.

[0292] In another aspect, insulation 2918 is provided along the tubing 2920. The insulation2918 is placed adjacent the burners 3238. Optionally, the insulation 2918 extends across theentire depth of the organic-rich rock formation 2905.

[0293] In the production of oil and gas resources, it may be desirable to use the producedhydrocarbons as a source of power for ongoing operations. This may be applied to thedevelopment of oil and gas resources from oil shale. Electrical power may be obtained fromturbines that turn generators. It may be economically advantageous to power the gas turbines byutilizing produced gas from the field. However, such produced gas must be carefully controlledso not to damage the turbine, cause the turbine to misfire, or generate excessive pollutants (e.g.,HOx).

[0294] One source of problems for gas turbines is the presence of contaminants within thefuel. Contaminants include solids, water, heavy components present as liquids, and hydrogensulfide. Additionally, the combustion behavior of the fuel is important Combustion parametersto consider include heating value, specific gravity, adiabatic flame temperature, flammabilitylimits, autoignition temperature, autoignition delay time, and flame velocity. Wobbe Index (WI)is often used as a key measure of fuel quality. WI is equal to the ratio of the lower heating valueto the square root of the gas specific gravity. Control of the fuel’s Wobbe Index to a target valueand range of, for example, ±10% or ±20% can allow simplified turbine design and increasedoptimization of performance, [0295] Fuel quality control may be useful for shale oil developments where the produced gascomposition may change over the life of the field and where the gas typically has significantamounts of C02, CO, and Hi in addition to light hydrocarbons. Commercial scale oil shaleretorting is expected to produce a gas composition that changes with time. PCT/US2008/005056 •55· WO 2008/143749 [0296] Inert gases in the turbine fuel can increase power generation by increasing mass flowwhile maintaining a flame temperature in a desirable range. Moreover inert gases can lowerflame temperature and thus reduce NOx pollutant generation. Gas generated from oil shalematuration may have significant C02 content. Therefore, in certain embodiments of theproduction processes, the C02 content of the fuel gas is adjusted via separation or addition in thesurface facilities to optimize turbine performance.

[0297] Achieving a certain hydrogen content for low-BTU fuels may also be desirable toachieve appropriate bum properties. In certain embodiments of the processes herein, the H2content of the fuel gas is adjusted via separation or addition in the surface facilities to optimizeturbine performance. Adjustment of H2 content in non-shale oil surface facilities utilizing lowBTU fuels has been discussed in the patent literature (e.g״ U.S. Pat. No. 6,684,644 and U.S. Pat.No. 6,838,049, the entire disclosures of which are hereby incorporated by reference).

[0299] 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 duringpyrolysis. This, in turn, indicates that formation pressure may be monitored to detect theprogress of a kerogen conversion process.

[0299] 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 aheater well, a richness of the formation hydrocarbons within the organic-rich rock formation, thedegree of heating, and/or a distance from a producer well.

[0300] 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 atvarying depths within a wellbore. In some embodiments, pressure may be measured at a PCT/US2008/005056 ־56- WO 2008/143749 producer 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.

[0301] 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.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 anincrease in fluid pressure may be caused by, for example, the generation of fluids duringpyrolysis of at least some formation hydrocarbons in the formation.

[0302] 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 fluidpressure 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.

[0303] Once pyrolysis has begun within an organic-rich rock formation, fluid pressure mayvary depending upon various factors. These include, for example, thermal expansion ofhydrocarbons, generation of pyrolysis fluids, rate of conversion, and withdrawal of generatedfluids 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.

[0304] 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 be PCT/U S2008/005056 -57- WO 2008/143749 accommodated if fluids generated from kerogen are unable to flow. The concept is illustrated inFigure 5.

[0305] 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 thatsubstantia] volume expansion occurred during the conversion process. This, in turn, increasespermeability of the rock structure.

[0306] In an embodiment, heating a portion of an organic-rich rock formation in situ to a.pyrolysis 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.

[0307] 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 heatedto 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.

[0308] 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 than PCT/US2008/005056 -58- WO 2008/143749 about 10 millidarcies, 100 millidaicies, 1 Darcy, 10 Darcies, 20 Darcies, or 50 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, 50 or 100 millidarcies, after heating the organic-rich rockformation.

[0309] 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.

[0310] 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.

[0311] 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. PCT/US2008/005056 -59- WO 2008/143749 [0312] The in situ heating of the matrix pyrolyzes at least a portion of the formationhydrocarbons to create hydrocarbon fluids. This, in turn, 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.

[0313] 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.

[0314] 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.

[0315] 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.

[0316] 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.

[0317] 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. PCT/US2008/005056 ־60־ WO 2008/143749 [0318] In one embodiment, operating conditions may be determined by measuring at leastone property of the organic-rich rock formation. The measured properties may be input into acomputer executable program. At least one property of the produced fluids selected to beproduced from the formation may also be input into the computer executable program. Theprogram may be operable to determine a set of operating conditions from at least the one or moremeasured properties. The program may also be configured to determine the set of operatingconditions from at least one property of the selected produced fluids. In this manner, thedetermined set of operating conditions may be configured to increase production of selectedproduced fluids from the formation.

[0319] Certain heater well embodiments may include an operating system that is coupled toany of the heater wells such as by insulated conductors or other types of wiring. The operatingsystem may be configured to interface with the heater well. The operating system may receive asignal (e.g., an electromagnetic signal) from a heater that is representative of a temperaturedistribution of the heater well. Additionally, the operating system may be further configured tocontrol the heater well, either locally or remotely. For example, the operating system may alter atemperature of the heater well by altering a parameter of equipment coupled to the heater well.Therefore, the operating system may monitor, alter, and/or control the heating of at least aportion of the formation.

[0320] 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.

[0321] 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.

[0322] 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 a WO 2008/143749 *61 - PCT/US2008/005056 numerical 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.

[0323] 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.

[0324] 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.

[0325] 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. £0326] 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.

<img img-format="tif" img-content="drawing" file="IL200834AD00631.tif" id="idf0007" />

PCT/US2008/005056 •62- WO 2008/143749 [0327] 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.

[0328] 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 certainembodiments, the hydrogen to carbon atomic ratio in produced fluid may be at leastapproximately 1.7 (e.g., 1.8,1.9, etc.).

[0329] 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.

[0330] 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.

[0331] 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 stress PCT7US2008/005056 -63- WO 2008/143749 greater 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. 5 [0332] The lithostatic stress of a section of an organic-rich formation can normally be estimated 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, thisvalue 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 the10 depth of the organic-rich rock formation interval by 0.9 psi/ft. Thus the lithostatic stress of a.section of an organic-rich formation occurring at about 1,000 ft can be estimated to be about (0.9psi/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 may

I 15 include heating a section of the organic-rich rock formation that is located at a depth greater than -200 ft below the earth's surface. Alternatively, the method may include heating a section of theorganic-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. 20 [0333] The organic-rich rock formation may be, for example, a heavy hydrocarbon formation or a solid hydrocarbon formation. Particular examples of such formations may includean oil shale formation, a tar sands formation or a coal formation. Particular formationhydrocarbons present in such formations may include oil shale, kerogen, coal, and/or bitumen.

[0334] The hydrocarbon fluid produced from the organic-rich rock formation may include 25 both 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-hydrocarbonfluids. Exemplary non-hydrocarbon fluids include, for example, water, carbon dioxide, hydrogensulfide, hydrogen, ammonia, and/or carbon monoxide.

[0335] The condensable hydrocarbon portion of the hydrocarbon fluid may be a fluid present30 within different locations associated with an organic-rich rock development project. For example, the condensable hydrocarbon portion of the hydrocarbon fluid may be a fluid presentwithin a production well that is in fluid communication with the organic-rich rock formation. PCT/US2008/005056 -64- WO 2008/143749

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.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 fluidtransportation 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. !0336] The following discussion of Figures 7-16 concerns data obtained in Examples 1 - 5which are discussed in the section labeled "Experiments". The data was obtained through theexperimental 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.

[0337] Figure 7 is a graph of the weight percent of each carbon number pseudo componentoccurring from C6 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 a PCT/US2008/005056 *65־ WO 2008/143749 percentage 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 2002represent 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 the1,000 psi stressed experiment of Example 4. From Figure 7 it can be seen that the hydrocarbonliquid 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 liquidand 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 psiand 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 level 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 produceda hydrocarbon liquid having C8 to C17 pseudo component concentrations greater than both theunstressed experiment represented by line 2002 and the 400 psi stressed experiment representedby 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) hydrocarbonliquid and the 400 psi stress experiment (Line 2003) hydrocarbon liquid. Thus pyrolyzing oil PCT/US2008/005056 ־66• WO 2008/143749 shale under increasing levels of lithostatic stress appears to produce hydrocarbon liquids havingincreasingly lighter carbon number distributions. (0338] 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 theS 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 202210 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 psi15 stressed 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 Cl 8 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 C2020 pseudo 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 online 2023, it is apparent that the intermediate level 400 psi stress experiment produced ahydrocarbon liquid having C8 to Cl 8 pseudo component concentrations as compared to the C20pseudo component between the unstressed experiment represented by line 2022 and the 1,000 psi25 stressed experiment represented by line 2024. Further, it is apparent that the weight percentageof 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 psi30 stress experiment produced a hydrocarbon liquid having C8 to C18 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 high PCT/US2008/005056 *67 WO 2008/143749 level 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.

[0339) 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 2040represents 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 C2S 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 rangeas compared to the C2S 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 online 2043, it is apparent that the intermediate level .400 psi stress experiment produced ahydrocarbon liquid having C7 to C24 pseudo component concentrations as compared to the C25pseudo component 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 unstressed PCT/US2008/005056 -68- WO 2008/143749 experiment 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.

[0340) 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 C6 to C36 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 shale PCT/U S2008/005056 -69- WO 2008/143749 under increasing levels of lithostatic stress produces hydrocarbon liquids having increasinglylighter carbon number distributions.

[0341] Figure 11 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from the normal־C6 alkane to the normal-C38 alkane for each of the three stress levels5 tested 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 gas10 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-C6 to normal-€38. The datapoints occurring on line 2082 represent the weight percent of each normal־C6 to normal-C38IS hydrocarbon 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 normaI־C6 to normal-038 hydrocarbon compoundfor the 1,000 psi stressed experiment of Example 4. From Figure 11 it can be seen that the20 hydrocarbon liquid produced in the unstressed experiment, represented by data points on line2082, contains a greater weight percentage of hydrocarbon compounds in the normal-Cl 2 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 experiment25 produced a hydrocarbon liquid having normal-Cl2 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-C12 to normal-C30 compoundconcentrations less than both the unstressed experiment represented by line 2082 and the 400 psi30 stressed 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. PCT/U S2008/005056 ·70־ WO 2008/143749 [0342] Figure 12 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal-C6 to normal־C38 as compared to the normal-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־C38 compound as compared to the normal-C20 compound found in the liquidphase. The x-axis 3001 contains the identity of each normal alkane hydrocarbon compound ratiofrom norma]־C6/normaI-C20 to norma]־C38/normal-C20. The data points occurring on line 3002represent the weight ratio of each normal־C6 to norma]-C38 hydrocarbon compound as comparedto the normal-C20 compound for the unstressed experiment of Example 1. The data pointsoccurring on line 3003 represent the weight ratio of each normal-C6 to normal-C38 hydrocarboncompound 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-C38 hydrocarbon compound as compared to the normal-C20 compound forthe 1,000 psi stressed experiment of Example 4. From figure 12 it can be seen that thehydrocarbon 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-C22 to normal-C34compound range as compared to the normal־C20 compound, 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 3003, it is apparent that the intermediate level400 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal-C17compound concentrations as compared to the normal־C20 compound between the unstressedexperiment represented by line 3002 and the 1,000 psi stressed experiment represented by line3004. Further, it is apparent that the weight percentage of heavier hydrocarbon components inthe 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 produceda hydrocarbon liquid having normal-C6 to normal-Cl7 compound concentrations as compared tothe 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-C34 PCT/US2008/005056 ־71־ WO 2008/143749 compound range as compared to the normal־C20 compound for the high level stress experimentrepresented 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 stress5 produces hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons.

[0343] Figure 13 is a graph of the weight percent of normal alkane hydrocarbon compoundsoccurring from normal־C6 to normal-C38 as compared to the normal־C25 hydrocarbon .compound for each of the three stress levels tested and analyzed in the laboratory experimentsdiscussed herein. The normal compound weight percentages were obtained as described for10 Figure 11. The y־axis 3020 represents the concentration in terms of weight ratio of each normal-C6 to normal־C38 compound as compared to the normal־C25 compound found in the liquidphase. The x־axis 3021 contains the identity of each normal alkane hydrocarbon compound ratio from normal-C6/normal־C25 to normal־C38/normal־C25. The data points occurring on line 3022 ( represent the weight ratio of each normal-C6 to normal־C38 hydrocarbon compound as compared ׳15 to the normal־C25 compound for the unstressed experiment of Example 1. The data pointsoccurring on line 3023 represent the weight ratio of each normal-C6 to normal-C38 hydrocarboncompound as compared to the normal-C25 compound for the 400 psi stressed experiment ofExample 3. While the data points occurring on line 3024 represent the weight ratio of each .normal־C6 to normal־C38 hydrocarbon compound as compared to the normal־C25 compound for20 the 1,000 psi stressed experiment of Example 4. From Figure 13 it can be seen that thehydrocarbon 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־C25 compound and a .greater weight percentage of heavier hydrocarbon components in the normal־C26 to normal־C3025 compound range as compared to the normal־C25 compound, 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 3023, it is apparent that the intermediate level400 psi stress experiment produced a hydrocarbon liquid having norraal־C6 to normal־C24compound concentrations as compared to the normal־C25 compound between the unstressed30 experiment represented by line 3022 and the 1,000 psi stressed experiment represented by line3024. Further, it is apparent that the weight percentage of heavier hydrocarbon components inthe normal־C26 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) PCT/US2008/005056 -72־ WO 2008/143749 hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produceda hydrocarbon liquid having normal־C6 to normal*C24 compound concentrations as compared tothe nont1al־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 the. 5 weight percentage of heavier hydrocarbon components in the normal*C26 to normal-C30compound range as compared to the normal-C2S compound for the high level stress experimentrepresented 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 stress10 produces hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons.

[0344) 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 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 forIS 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/nonnal-C29 to normal־C38/normal־C29. The data points occurring on-line 3042represent the weight ratio of each normal־C6 to normal-C38 hydrocarbon compound as compared20 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*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 for25 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 line3042, contains a lower weight percentage of lighter normal alkane hydrocarbon components inthe normal-C6 to normal*C26 compound range as compared to the normal*C29 compound, bothas compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress30 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 stress PCT/US2008/005056 -73- WO 2008/143749 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 line3043. This analysis further supports the relationship that pyrolyzing oil shale under increasing5 levels of lithostatic stress produces hydrocarbon liquids having lower concentrations of normalalkane hydrocarbons.

[0345] 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 and10 pseudo component weight percentages were obtained as described for Figures 7 and 11. Forclarity, 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־C6/pseudo C6 to normal-C38/pseudo15 C38 compound found in the liquid phase. The x־axis 3061 contains the identity of each normal alkane 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 norma]*C6/pseudo20 C6 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 tonormal-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, representedby data points on line 3062, contains a greater weight percentage of normal alkane hydrocarbon25 compounds 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 unstressed30 experiment 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 increasing PCT/US2008/005056 ־74- WO 2008/143749 levels 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.

[0346] 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.

[0347] 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 Cl3 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, atotal 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 embodiments PCT/US2008/005056 -75- WO 2008/143749 described in this paragraph may be combined with any of the other aspects of the inventiondiscussed herein.

[0348] 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, thecondensable 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 orless 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 CU 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 C20 PCT/US2008/005056 *76- WO 2008/143749 weight ratio less than 6.0 or less than S.O. 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, the .condensable hydrocarbon portion may have a total Cl5 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-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.

[0349] 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 C12 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 ratio PCT/US2008/005056 -77- WO 2008/143749 greater than 15.0, a total Cl 1 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.

[0350] In some embodiments die 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, great«* 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 condensable PCT/US2008/005056 -78- WO 2008/143749 hydrocarbon 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 Cl2 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 1010, greaterthan 12.0, or greater than 14.0. In alternative embodiments, the condensable hydrocarbon portionmay have a total C13 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 ratiogreater than 6.0. Alternatively, the condensable hydrocarbon portion may have a total C14 tototal C25 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 C25 weightratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portionhas a total C15 to total C2S weight ratio greater than 6.0. Alternatively, the condensablehydrocarbon portion may have a total CIS to total C25 weight ratio greater than 8.0, or greaterthan 10.0. In alternative embodiments, the condensable hydrocarbon portion may have a totalC15 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 Cl7 to total C25 weightratio less than 20.0. In some embodiments the condensable hydrocarbon portion has a total C18to total C25 weight ratio greater than 4.5. Alternatively, the condensable hydrocarbon portionmay have a total Cl8 to total C25 weight ratio greater than 5.0 or greater than 5.5. In alternativeembodiments, the condensable hydrocarbon portion may have a total Cl8 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 of

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PCT/US2008/005056 -79- WO 2008/143749 described in this paragraph may be combined with any of the other aspects of the inventiondiscussed herein.

[0351] 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 Cl 1 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 CIS 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 C18 to total C29 weight ratio greater than 8.8, a total C19 to totalC29 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 poition 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 CU 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 C14 to.total C29 weight ratio greater than 13.0, a total CIS to total C29 weight ratio greaterthan 13.0, a total C16 to total C29 weight ratio greater than 10.0, a total C17 to total C29 weightratio greater than 11.0, a total Cl 8 to total C29 weight ratio greater than 9.0, a total C19 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 weightratio greater than 27.0, a total CI2 to total C29 weight ratio greater than 25.0, and a total C13 tototal C29 weight ratio greater than 22.0, a total CI4 to total C29 weight ratio greater than 18.0, atotal CIS to total C29 weight ratio greater than 18.0, a total 06 to total C29 weight ratio greaterthan 16.0, a total 07 to total C29 weight ratio greater than 13.0, a total 08 to total C29 weightratio greater than 10.0, a total 09 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., PCT/US2008/005056 -80- WO 2008/143749 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.

[0352] 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 someembodiments 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 ponion 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 Cl 1 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 C12 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 to PCT/US2008/005056 *81 - WO 2008/143749 total 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 C15 to total C29weight ratio greater than 12.0. Alternatively, the condensable hydrocarbon portion may have atotal 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 condensablehydrocarbon portion may have a total Cl6 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 ratio .greater than 10.0. Alternatively, the condensable hydrocarbon portion may have a total C17 tototal 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 C18to total C29 weight ratio greater than 9.0 or greater than 10.0. In alternative embodiments, thecondensable 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.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. PCT/US2008/005056 -82- WO 2008/143749 [0353] In some embodiments the condensable hydrocarbon portion may have the one or moreof 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 3.2 5 and 8.0. In alternative embodiments the condensable hydrocarbon portion has one or more of atotal 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 CI2 tototal C20 weight ratio between 3.0 and 6.0, and a total Cl 3 to total C20 weight ratio between 3.3and 7.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a10 total C9 to total C20 weight ratio between 4.6 and 5.5, a total CIO to total C20 weight ratiobetween 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 the15 conjunction "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 this20 paragraph may be combined with any of the other aspects of the invention discussed herein.

[0354] 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 some 25 embodiments 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,30 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 Cl2 to total C20 weight ratio between 2.8 and 6.2, between 3.2 and 6.2, PCT/US2008/005056 -83- WO 2008/143749 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.

[0355] 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 C13to 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 and24,0, a total Cll 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 Cl 1 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.

[0356] 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 Cl 1 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 condensable PCT/U S2008/005056 ־84- WO 2008/143749 hydrocarbon 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 Cl3 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.

[0357] 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 thecondensable hydrocarbon portion has one or more of a total CIO to total C29 weight ratiobetween 17.0 and 58.0, a total Cl 1 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 has oneor more of a total CIO to total C29 weight ratio between 20.0 and 58.0, a total Cll to total C29weight ratio between 18.0 and 52.0, a total C12 to total C29 weight ratio between L8.0 and 50.0,and a total C13 to total C29 weight ratio between 18.0 and 50.0. As used in this paragraph and inthe claims, the phrase "one or more" followed by a listing of different compound or componentratios with 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 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.

[0358] In some embodiments the condensable hydrocarbon portion has a total CIO to totalC29 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 and WO 20087143749 .35 . PCT/US2008/005050 54.0. Alternatively, the condensable hydrocarbon portion may have a total Cll to total C29weight 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 5 53.0. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C29 weight ratio between 14.5 and 51.0, between 16.0 and 51.0, between 18.0 and 51.0, between 20.0and 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 Cl 3 to total C2910 weight ratio between 17.0 and 60.0, between 18.0 and 60.0, between 20.0 and 60.0, between 22.0 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.

[0359] In some embodiments the condensable hydrocarbon portion may have one or more of .a normal-C7 to normal-020 weight ratio greater than 0.9, a normal־C8 to normal-020 weight15 ratio greater than 2.0, a normal-09 to normal־C20 weight ratio greater than 1.9, a normal-CIO tonormal-C20 weight ratio greater than 2.2, a normal-Cll to normal-020 weight ratio greater than1.9, a normal-012 to normal-020 weight ratio greater than 1.9, a normal-Cl3 to normal-C20weight ratio greater than 2.3, a normal-014 to normal-020 weight ratio greater than 1.8, anormal-015 to normal-C20 weight ratio greater than 1.8, and normal-016 to normal-C20 weight20 ratio greater than 1.3. In alternative embodiments the condensable hydrocarbon portion has one .or more of a normal-07 to normal-C20 weight ratio greater than 4.4, a normal-08 to norma]-C20weight ratio greater than 3.7, a normal-09 to normal-020 weight ratio greater than 3.5, a normal-CIO to normaI-C20 weight ratio greater than 3.4, a normal-Cll to normal-C20 weight ratiogreater than 3.0, and a normal-012 to normal-020 weight ratio greater than 2.7. In alternative25 embodiments the condensable hydrocarbon portion has one or more of a normal-07 to normal-C20 weight ratio greater than 4.9, a normal-08 to normal-020 weight ratio greater than 4.5, anormal-09 to normal-C20 weight ratio greater than 4.4, a normal-CIO to normal-020 weightratio greater than 4.1, a normal-Cl 1 to norma!-C20 weight ratio greater than 3.7, and a normal-C12 to normal-020 weight ratio greater than 3.0. As used in this paragraph and in the claims, the30 phrase ”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 a

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FCT/US2008/005056 -86- WO 2008/143749 particular 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.

[0360] 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 nomnal*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-07 to normal־C20 weight ratio less than 8.0 or less than 7.0. In some embodiments the condensable hydrocarbon portion has a normal-C8to 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*C2Q weight ratio less than 8.0 or less than 7.0. In some embodiments the condensable hydrocarbon portion has a normal-C9to normal*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-09 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-ClO 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-Cll to normal-C20 weight ratio greater than 1.9.Alternatively, the condensable hydrocarbon portion may have a normal-Cll to normal*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-C12 to normal־C20 weight ratio greater than 1.9. Alternatively, thecondensable hydrocarbon portion may have a normal-CI2 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-Cl 2 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 hydrocarbon PCT/US2008/005056 -87- WO 2008/143749 portion may have a normal-Cl 3 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-Cl3 to normaI-C20 weight ratio less than 6.0 or less than 5.0. In some embodiments thecondensable hydrocarbon portion has a normal-CI4 to normal־C20 weight ratio greater than 1.8. 5 Alternatively, the condensable hydrocarbon portion may have a normal-Cl4 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 anorraal-CI5 to normaI־C20 weight ratio greater than 1.8. Alternatively, the condensable10 hydrocarbon portion may have a normal-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-015 to normal-C20 weight ratio less than 6.0 or less than 4.0. In someembodiments the condensable hydrocarbon portion has a normal-Cl6 to norma)-C20 weight ratiogreater than 1.3. Alternatively, the condensable hydrocarbon portion may have a norma)-C16 to15 norma!-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-Cl6 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 by20 any 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.

[0361] In some embodiments the condensable hydrocarbon portion may have one or more ofa normal-C7 to normal־C25 weight ratio greater than 1.9, a normal-C8 to normal-C25 weight25 ratio greater than 3.9, a normal-C9 to normal-C25 weight ratio greater than 3.7, a normal־C10 tonormal-C25 weight ratio greater than 4.4, a normal-Cll to normal־C25 weight ratio greater than3.8, a normal-C12 to normal-C25 weight ratio greater than 3.7, a normal-Cl3 to normal-C25weight ratio greater than 4.7, a normal-C14 to normal־C25 weight ratio greater than 3.7, anormal-015 to normal-C25 weight ratio greater than 3.7, a normal־C16 to nomaal-C25 weight30 ratio greater than 2.5, a normal־C17 to normal-C25 weight ratio greater than 3.0, and a normal-C18 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-C8 to normal-C25 weight ratio greater than 8.0, a normal-C9 to normal-C25 weightratio greater than 7.0, a normal-ClO to normal-C25 weight ratio greater than 7.0, a normal-Cll to PCT/US2008/005056 -88- WO 2008/143749 normal-025 weight ratio greater than 7.0, and a normal-012 to normal-025 weight ratio greaterthan 6.0. In alternative embodiments the condensable hydrocarbon portion has one or more of anormal-07 to normal-025 weight ratio greater than 10.0, a normal-08 to normal-025 weightratio greater than 12.0, a normal-09 to normal-025 weight ratio greater than 11.0, a noimal-ClOto normal-025 weight ratio greater than 11.0, a normal-Cll to normal-025 weight ratio greaterthan 9.0, and a normal-012 to normai-025 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 twoor 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 combinedwith, any of the other aspects of the invention discussed herein. (0362] In some embodiments the condensable hydrocarbon portion has a normal-C7 tonormal-C25 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 condensablehydrocarbon portion may have a normal־C7 to normal-C25 weight ratio less than 35.0 or lessthan 25.0. In some embodiments the condensable hydrocarbon portion has a normal-C8 tonormal-C25 weight ratio greater than 3.9. Alternatively, the condensable hydrocarbon portionmay have a normal-C8 to normal-C25 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 condensablehydrocarbon portion may have a norma!-C8 to normal-C25 weight ratio less than 35.0 or lessthan 25.0. In some embodiments the condensable hydrocarbon portion has a normal-C9 tonormal-C25 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portionmay have a normal-C9 to normal-C25 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 condensablehydrocarbon portion may have a normal-C9 to normal-025 weight ratio less than 35.0 or lessthan 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-CIO to normal-C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the PCT/US2008/005056 -89- WO 2008/143749 condensable hydrocarbon portion has a normal-Cl 1 to normal-C25 weight ratio greater than 3.8.Alternatively, the condensable hydrocarbon portion may have a normal-Cl l to normal-C25weight 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-Cll tonormal-C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensablehydrocarbon portion has a normal-Cl2 to normal-C25 weight ratio greater than 3.7.Alternatively, the condensable hydrocarbon portion may have a normal-C12 to nonnal-C25weight 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 normaI־C12 to normal-C25weight ratio less than 30.0 or less than 20.0. In some embodiments the condensable hydrocarbonportion has a normal-Cl3 to normal-C25 weight ratio greater than 4.7. Alternatively, thecondensable hydrocarbon portion may have a normal-Cl3 to normaI-C25 weight ratio greaterthan 5.0, greater than 6,0, or greater than 7.5. In alternative embodiments, the condensablehydrocarbon portion may have a normaI-CI3 to n01mal-C25 weight ratio less than 25.0 or lessthan 20.0. In some embodiments the condensable hydrocarbon portion has a normal-Cl4 tonormal-C25 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portionmay have a normal-C14 to normal-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-Cl5 to normal-C25 weight ratio greater than 3.7.Alternatively, the condensable hydrocarbon portion may have a normal-C15 to normal-C25weight ratio greater than 4.2 or greater than 5.0. In alternative embodiments, the condensablehydrocarbon portion may have a normal-Cl5 to norma)-C25 weight ratio less than 25.0 or lessthan 20.0. In some embodiments the condensable hydrocarbon portion has a normal-C16 tonormal-C25 weight ratio greater than 2.5. Alternatively, the condensable hydrocarbon portionmay have a normal-Cl6 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-C16 to normal־C25 weight ratio less than 20.0 or less than 15.0. In some embodiments thecondensable hydrocarbon portion has a normal-Cl 7 to normal-C25 weight ratio greater than 3.0.Alternatively, the condensable hydrocarbon portion may have a normal־C17 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-Cl8 to normal-C25 weight ratiogreater than 3.4. Alternatively, the condensable hydrocarbon portion may have a normal-C18 to PCT/US2008/005056 -90- WO 2008/143749 normal-025 weight ratio greater than 3.6 or greater than 4.0. In alternative embodiments, thecondensable hydrocarbon portion may have a normal־C18 to normal-C25 weight ratio less than 15.0, 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.

[0363] In some embodiments the condensable hydrocarbon portion may have one or more ofa normal-07 to normal-C29 weight ratio greater than 18.0, a normal-08 to norma]-C29 weightratio greater than 16.0, a normal-09 to normal-C29 weight ratio greater than 14.0, a normal-010to normal-029 weight ratio greater than 14.0, a normal-Ol 1 to normal-029 weight ratio greaterthan 13.0, a normal־C12 to normal-029 weight ratio greater than 11.0, a normal-C13 to normal-C29 weight ratio greater than 10.0, a normal-014 to normal-029 weight ratio greater than 9.0, anonnal-C15 to n01mal-C29 weight ratio greater than 8.0, a normal-016 to normal-029 weightratio greater than 8.0, a normal-017 to normal-029 weight ratio greater than 6.0, a normal-C18 tonormal-029 weight ratio greater than 6.0, a noimal-019 to normal-029 weight ratio greater than 5.0, a normal-C20 to normal-029 weight ratio greater than 4.0, a normal-021 to normal-029weight ratio greater than 3.6, and a normal-022 to normal-029 weight ratio greater than 2.8. Inalternative embodiments the condensable hydrocarbon portion has one or more of a normal-07 tonormal-029 weight ratio greater than 20.0, a normal-C8 to normal-029 weight ratio greater than 18.0, a normal-09 to normal-029 weight ratio greater than 17.0, a normal-010 to normal-029weight ratio greater than 16.0, a normal-Cll to normal-029 weight ratio greater than 15.0, anormal-012 to normal-029 weight ratio greater than 12.5, a normal־C13 to normal־C29 weightratio greater than 11.0, a normal-014 to normal-029 weight ratio greater than 10.0, a normal-015to normal-029 weight ratio greater than 8.0, a normal-016 to normal-029 weight ratio greaterthan 8.0, a normal-017 to normal-029 weight ratio greater than 7.0, a normal-018 to normal-029weight ratio greater than 6.5, a normal-019 to normal-029 weight ratio greater than 5.5, anormal-020 to normal-029 weight ratio greater than 4.5, and a normal-021 to normal-029weight ratio greater than 4.0. In alternative embodiments the condensable hydrocarbon portionhas one or more of a normal-07 to normal-029 weight ratio greater than 23.0, a normal-08 tonormal-029 weight ratio greater than 21.0, a normal-09 to normal-029 weight ratio greater than 20.0, a normal-C10 to normal־C29 weight ratio greater than 19.0, a normal-Cll to normal-029weight ratio greater than 17.0, a normal-012 to normal-029 weight ratio greater than 14.0, anormal-013 to normal-029 weight ratio greater than 12.0, a normal-014 to normal-C29 weight PCTAJS2008/005056 ־91־ WO 2008/143749 ratio greater than 11.0, a normal־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 n01mal-C29weight ratio greater than 6.5, a norraal-C20 to norma!-C29 weight ratio greater than 4.8, and anormal־C2l 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 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.

[0364] In some embodiments the condensable hydrocarbon portion has a normal־C7 tonormal-C29 weight ratio greater than 18.0. Alternatively, the condensable hydrocarbon portionmay have a normai־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 n01mal־C8 to normal־C29 weight ratio less than 85.0 or lessthan 75.0. In some embodiments the condensable hydrocarbon portion has a normaI*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*C9 to norma!־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 than PCT/US2008/005056 -92- WO 2008/143749 13.0. 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 normaI־C12 to normal-C29 weight ratio greater than 11.0.Alternatively, the condensable hydrocarbon portion may have a n01mal־C12 to normal־C29 ·weight 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-Cl 2 tonormal-C29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensablehydrocarbon portion has a normal-C13 to normal-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 no1mal-C29weight ratio less than 70.0 or less than 60.0. In some embodiments the condensable hydrocarbonportion has a n0rmal-C14 to normal־C29 weight ratio greater than 9.0. Alternatively, thecondensable hydrocarbon portion may have a nomaal-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-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 nonnal־C15 to normal-C29 weight ratio greater than 12.0 or greater than 16.0. Inalternative embodiments, the condensable hydrocarbon portion may have a normal-015 tonormal-C29 weight ratio less than 60.0 or less than 50.0. In some embodiments the condensablehydrocarbon portion has a normal-06 to normal-C29 weight ratio greater than 8,0.Alternatively, the condensable hydrocarbon portion may have a normal-06 to normal-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־C17 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־C17 to norma!-C29 weight ratio less than 45.0. In some embodiments thecondensable hydrocarbon portion has a normal-C18 to normal-C29 weight ratio greater than 6.0.Alternatively, the condensable hydrocarbon portion may have a normal־C18 to normal-029

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PCT/US2008/005056 -93- WO 2008/143749 weight ratio greater than 8.0 or greater than 10.0. In alternative embodiments, the condensablehydrocarbon portion may have a notmal-C18 to normal-C29 weight ratio less than 35.0. In someembodiments the condensable hydrocarbon portion has a normal-019 to normal-029 weight ratiogreater than 5.0. Alternatively, the condensable hydrocarbon portion may have a normal-019 tonormal-029 weight ratio greater than 7.0 or greater than 9.0. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-019 to notmal-C29 weight ratio less than30.0. In some embodiments the condensable hydrocarbon portion has a normal-C20 to normal-C29 weight ratio greater than 4.0. Alternatively, the condensable hydrocarbon portion may havea normal-C20 to normal-029 weight ratio greater than 6.0 or greater than 8.0. In alternativeembodiments, the condensable hydrocarbon portion may have a normal-020 to normal-C29weight ratio less than 30.0. In some embodiments the condensable hydrocarbon portion has anormal-021 to normal-029 weight ratio greater than 3,6. Alternatively, the condensablehydrocarbon portion may have a normal-021 to normal-029 weight ratio greater than 4.0 orgreater than 6.0. In alternative embodiments, the condensable hydrocarbon portion may have anormal-021 to normal-029 weight ratio less than 30.0. In some embodiments the condensablehydrocarbon portion has a normal-C22 to normal-029 weight ratio greater than 2.8.Alternatively, the condensable hydrocarbon portion may have a normal-022 to normal-029weight ratio greater than 3.0. In alternative embodiments, the condensable hydrocarbon portionmay have a normal-022 to noimal-029 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.

[0365] In some embodiments the condensable hydrocarbon portion may have one or more ofa normal-010 to total CIO weight ratio less than 0.31, a normal-Cl 1 to total Cl l weight ratio lessthan 0.32, a normal-012 to total C12 weight ratio less than 0.29, a normal-013 to total C13weight ratio less than 0.28, a normal-014 to total C14 weight ratio less than 0.31, a normal-C15to total C15 weight ratio less than 0.27, a normal-016 to total C16 weight ratio less than 0.31, anormal-017 to total C17 weight ratio less than 0.31, a normal-018 to total C18 weight ratio lessthan 0.37, normal־C19 to total C19 weight ratio less than 0.37, a normal-C2G to total C20 weightratio less than 0.37, a normal-021 to total C21 weight ratio less than 0.37, a normal-022 to totalC22 weight ratio less than 0.38, normal־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-025 to total C25 weight ratio less than PCT/US2008/005056 -94 - WO 2008/143749 0.53. 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־C15 to total C15 weight ratio less than 0.24, a normal-Cl6to total C16 weight ratio less than 0.25, a normal&gt;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 anormal-C25 to total C25 weight ratio less than 0.49. In alternative embodiments the condensablehydrocarbon portion has one or more of a normal-Cl I to total Cll weight ratio less than 0.28, anormal-02 to total 02 weight ratio less than 0.25, a normal־C13 to total 03 weight ratio lessthan 0.24, a normal־C14 to total 04 weight ratio less than 0.27, a normal-Cl5 to total 05weight ratio less than 0.22, a normal-C16 to total 06 weight ratio less than 0.23, a normal-C17to total 07 weight ratio less than 0.25, a normal-Cl8 to total 08 weight ratio less than 0.28,normal-C19 to total 09 weight ratio less than 0.31, a normal-C20 to total C20 weight ratio lessthan 0.29, a normal-C21 to total C21 weight ratio less than 0.30, a nonnal-C22 to total C22weight ratio less than 0.28, normal־C23 to total C23 weight ratio less than 0.33, a normal־C24 tototal 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 ofdifferent 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, aparticular 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. {0366} In some embodiments the condensable hydrocarbon portion has a normal-CIO to totalCIO weight ratio less than 0.31. Alternatively, the condensable hydrocarbon portion may have anormal-C10 to total CIO weight ratio less than 0,30 or less than 0.29. In alternativeembodiments, the condensable hydrocarbon portion may have a normal־C10 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 Cl 1 weight ratio less than 0.32. Alternatively, the condensablehydrocarbon portion may have a normal-Cl 1 to total Cll weight ratio less than 0.31, less than PCT/US2OO8/005056 ־95- WO 2008/143749 0.30, or less than 0.29. In alternative embodiments, the condensable hydrocarbon portion mayhave a normal-Ol to total Cll weight ratio greater than 0.15 or greater than 0.20. In someembodiments the condensable hydrocarbon portion has a normal-Cl 2 to total C12 weight ratioless than 0.29. Alternatively, the condensable hydrocarbon portion may have a normal-02 to5 total C12 weight ratio less than 0.26, or less than 0.24. In alternative embodiments, thecondensable hydrocarbon portion may have a normal־CI2 to total 02 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has anormal-03 to total C13 weight ratio less than 0.28. Alternatively, the condensable hydrocarbonportion may have a normaI־C13 to total 03 weight ratio less than 0.27, less than 0.25, or less10 than 0.23. In alternative embodiments, the condensable hydrocarbon portion may have a normal-03 to total 03 weight ratio greater than 0.10 or greater than 0.15. In some embodiments thecondensable hydrocarbon portion has a normal-C14 to total 04 weight ratio less than 0.31.Alternatively, the condensable hydrocarbon portion may have a normal-04 to total 04 weightratio less than 0.30, less than 0.28, or less than 0.26. In alternative embodiments, the15 condensable hydrocarbon portion may have a normal04־ to total 04 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has anormal-015 to total 05 weight ratio less than 0.27. Alternatively, the condensable hydrocarbonportion may have a normal־C15 to total 05 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-20 05 to total 05 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C16 to total 06 weight ratio less than 0.31.Alternatively, the condensable hydrocarbon portion may have a normal־C16 to total 06 weightratio less than 0.29, less than 0.26, or less than 0.24. In alternative embodiments, thecondensable hydrocarbon portion may have a normaI־C16 to total 06 weight ratio greater than25 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-07 to total 07 weight ratio less than 0.31. Alternatively, the condensable hydrocarbonportion may have a normal-017 to total 07 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-07 to total 07 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the30 condensable hydrocarbon portion has a normal-C18 to total 08 weight ratio less than 0.37.Alternatively, the condensable hydrocarbon portion may have a norma!-C18 to total 08 weightratio less than 0.35, less than 0.31, or less than 0.28. In alternative embodiments, thecondensable hydrocarbon portion may have a normal-08 to total 08 weight ratio greater than0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a

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PCT/US2008/005056 -96- WO 2008/143749 norma!־C19 to total C19 weight ratio less than 0.37. Alternatively, the condensable hydrocarbonportion may have a normal*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-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 anormal-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 thecondensable hydrocarbon portion has a normal-C22 to total C22 weight ratio less than 0.38.Alternatively, the condensable hydrocarbon portion may have a normal-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 anormal-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.Alternatively, the condensable hydrocarbon portion may have a normal-024 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-024 to total 024 weight ratio greater than0.15 or greater than 0.20. In some embodiments the condensable hydrocarbon portion has anormal-025 to total C25 weight ratio less than 0.48. Alternatively, the condensable hydrocarbonportion may have a normal-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 beappreciated that ranges formed by any combination of these limits are within the scope of the PCT/US2008/005056 -97- WO 2008/143749 invention unless otherwise indicated. The embodiments described in this paragraph may becombined with any of the other aspects of the invention discussed herein.

[0367] The use of "total C_" (e.g.p total CIO) herein and in the claims is meant to refer to theamount of a particular pseudo component found in a condensable hydrocarbon fluid determinedas 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 eachpseudo-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-oi!systems using methane interaction coefficients, J. Petroleum Technology (Nov. 1978), 1649-1655) as described in the Experiments section, including the exemplary molar and weightpercentage determinations.

[0368] The use of "normal-CJ' (e.g., normal־C10) 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-CJ' 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.

[0369] The following discussion of Figure 16 concerns data obtained in Examples 15־which are discussed in the section labeled "Experiments". The data was obtained through theexperimental procedures, gas sample collection procedures, hydrocarbon gas sample gas PCT/US2008/005056 -98- WO 2008/143749 chromatography (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.

[0370] 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 collectionprocedures, 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 H2S), any of the unidentified hydrocaibon gas species listed inTables 2,4, S, 7, or 9 (e.g״ peak numbers 2,6, 811,13־, i5-22,24-26, 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 norma]pentane, 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 308SA-I and 3086A-1 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 3082A PCT/US2008/005056 -99- WO 2008/143749 and 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-1 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 3085A and 3086A concentration and the highest propaneconcentrations 3085C and 3086C, as compared to both the unstressed experiments representedby 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. {0371} 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.

[0372] 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.

[0373] 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 hydrocarbon PCT/US2008/005056 *100- WO 2008/143749 portion 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.

[0374] 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 orgreater than 0.75 weight percent. Alternatively, the condensable hydrocarbon portion may have amethyl-cyclohexane content less than 1.2 or 1.0 weight percent.

[0375] 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.

[0376] 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.

[0377] 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. PCT/US2008/005056 -101- WO 2008/143749 [0376] 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 !ithostatic 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.

[0379] 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 formationsurrounded 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.

[0360] 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.

[0381] 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 asingle 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.

[0382] 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, PCT/US2008/005056 -102- WO 2008/143749 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.

[0383] A second method of altering lithostatic stress involves causing a region of asubsurface formation to expand and push against the overburden with greater force thanneighboring 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.

[0384] 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.

[0385] 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 rock PCT/US2008/005056 -103- WO 2008/143749 formation such that the thermal expansion within the first region is greater than that within theneighboring regions of the organic-rich rock formation. !0386] 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.

[0387] 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.

[0368] : 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 tosubstantia] 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 fluidproduction 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.

[0389] 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, PCT/US2008/005056 -104- WO 2008/143749 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.

[0390] 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.

[0391] The water-soluble minerals, may include sodium. The water-soluble minerals mayalso include nahcolite (sodium bicarbonate), soda ash (sodium carbonate), dawsonite(NaAl(C(93XOi/)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 reinjected 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.

[0392] 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.

[0393] 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, flourides and phenols. If oxygen or air is PCT/US2008/005056 -105- WO 2008/14374? employed, 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.

[0394] 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 toremove 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.

[0395] 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.

[0396] 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 unmatured PCT/U S2008/005056 • 106- WO 2008/143749 organic-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 methodS may be combined with any of the other aspects of the invention as discussed herein.

[0397] 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 of10 these processes are individually known in the art. Exemplary adsorbent materials may includeactivated carbon, clay, or fuller’s earth.

[0396] 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 and15 adsorbed 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 will 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. 20 [0399] Simultaneous development of shale oil resources and natural gas resources in the same 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.

[0400] Figure 6 illustrates a schematic diagram of an embodiment of surface facilities 7025 that 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 production30 scheme 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 remove

<img img-format="tif" img-content="drawing" file="IL200834AD01081.tif" id="idf0012" />

PCT/US2008/005056 - 107- WO 2008/143749 water 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 methods5 described 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 produced 10 fluids 85. Excess gas, if available, may be exported for sale.

[0401] 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-butane,isobutane), noncondensable hydrocarbon alkene species (e.g., ethene, propene), condensable 15 hydrocarbon species composed of (alkanes, olefins, aromatics, and polyaromatics among others),C02, CO, H2, H2S, and NHy [0402] . 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. 20 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. 25 [0403] Water in addition to condensable hydrocarbons may be dropped out of the gas when reducing 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.

[0404] Methods to remove CO%, as well as other so-called acid gases (such as H^S), from 30 produced 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 species PCT/US2008/005056 -108- WO 2008/143749 to 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.

[0405] Acid gas removal may also be effectuated through the use of distillation towers. Suchtowers may include an intermediate freezing section wherein frozen C02 and H!S 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.

[0406] 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., CO!,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

[0407] 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 L 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-IB. The core specimens taken from this block, as described in the following PCT/US2008/005056 -109- WO 2008/143749 examples, 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 [0408] 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 placed . into 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 presentin the chamber and the vessel pressurized to 500 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 °Cfurnace 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.

[0409] 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 cylinder150 milliliters in volume was evacuated, attached to the Parr vessel and the pressure allowed toequilibrate. 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-axis 4001 represents the retention time in minutes. In Figure 19 peak4002 represents the response for methane, peak 4003 represents the response for ethane, peak4004 represents the response for propane, peak 4005 represents the response for butane, peak4006 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. PCT/US2008/005056 - 110- WO 2008/143749

Table 2

Peak and Area Details for Fig. 19 - Example 1 - 0 psi 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 1.2647364 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 ? 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 7 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 7 19 7.603 3.99227 7 20 8.138 13.15432 7 21 8.223 13.01887 7 22 8.345 103.15615 7 23 8.495 291.26767 2-methyl pentane 24 8.651 15.64066 ? 25 8.884 91.85989 ? 26 9.165 40.09448 ? 27 9.444 534.44507 n-Hexane 28 9.557 2.64731 ? 29 9.650 32.28295 ? 30 9.714 52.42796 ? 31 9.793 42.05001 7 32 9.852 8.93775 ? 33 9.914 4.43648 ? 34 10.013 24.74299 ? 35 10.229 13.34387 ? 36 10.302 133.95892 ? 37 10.577 2.67224 7 38 11.252 27.57400 ? 39 11.490 23.41665 7 40 11.567 8.13992 ? 41 11.820 32.80781 7 42 11.945 4.61821 7 43 12.107 30.67044 ? 44 12.178 2.58269 ? 45 12.308 13.57769 7 PCT/US2008/005056 - Ill - WO 2008/143749

Table 2. (Cont.)

Peak Number Ret. Time[min] Area rpA*s1 Compound Name 46 12.403 12.43018 ? 47 12.492 34.29918 7 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 ? 53 13.317 7.21400 7 54 13.443 4.22721 ? 55 13.525 35.08374 7 56 13.903 18.48654 7 57 14.095 6.39745 7 58 14.322 3.19935 7 59 14.553 8.48772 7 60 14.613 3.34738 7 61 14.730 5.44062 7 62 14.874 40.17010 7 63 14.955 3.41596 ? 64 15.082 3.04766 7 65 15.138 7.33028 7 66 15.428 2.71734 ? 67 15.518 11.00256 ? 68 15.644 5.16752 7 69 15.778 45.12025 ? 70 15.855 3.26920 7 71 16.018 3.77424 7 72 16.484 4.66657 7 73 16.559 5.54783 7 74 16.643 10.57255 7 75 17.261 2.19534 7 76 17.439 10.26123 7 77 17.971 1.85618 7 78 18.097 11.42077 7 [0410] The 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. PCT/US2008/005056 -112 WO 2008/143749

Table 3

Peak and Area Details for Fig. 20 - Example 1 - 0 psi 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) to 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 : 532519״e4 PCT/US2008/005056 ־113- WO 2008/143749

Example 2 [0411] 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 l־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.

[0412] As described in Example 1, the room temperature Pan־ 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. PCT/US2008/005056 -114- WO 2008/143749

Table 4

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

Peak Number Ret Time[min] Area [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 1C4 6 4.917 1035.25513 ? 7 5.022 5689.08887 n-Butane 8 5.298 450.26572 ? 9 5.578 302.56229 ? 10 6.125 33.82201 7 11 6.372 1136.37097 iC5 12 6.736 263.35754 ? 13 6.898 2254.86621 n־Pentane 14 7.066 7.12101 7 15 7.133 258.31876 7 16 7.293 126.54671 7 17 7.378 155.60977 7 18 7.598 6.73467 7 19 7.758 679.95312 7 20 8.133 27.13466 7 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 ד 29 9.642 26.86672 ? 30 9.705 49.83235 ? 31 9.784 52.11239 7 32 9.843 9.03158 7 33. 9.904 6.18217 ? 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 7 39 11.240 46.79988 7 40 11.478 29.59438 7 41 11.555 12.84377 7 42 11.809 38.67433 ? 43 11.935 5.68525 7 44 12.096 31.29068 ? 45 12.167 5.84513 7 PCT/US2008/005056 - 115- WO 2008/143749

Table 4. (Cont.)

Peak Number Ret. Timertnin] Area [pA*s] Compound Name 46 12.297 15.52042 ? 47 12.393 13.54158 9 48 12.483 30.95983 ? 49 12.669 20.21915 ? 50 12.929 229.00655 ? 51 13.063 6.38678 7 52 13.196 10.89876 ? 53 13.306 7.91553 ? 54 13.435 5.05444 ? 55 13.516 44.42806 ? 56 13.894 20.61910 9 57 14.086 8.32365 ? 58 14.313 2.80677 ד 59 14.545 9.18198 ? 60 14.605 4.93703 ? 61 14.722 5.06628 ? 62 14.865 46.53282 ? 63 14.946 6.55945 7 64 15.010 2.85594 ? 65 15.075 4.05371 7 66 15.131 9.15954 ? 67 15.331 2.16523 7 68 15.421 3.03294 7 69 15.511 9.73797 7 70 15.562 5.22962 7 71 15.636 3.73105 7 72 15.771 54.64651 7 73 15.848 3.95764 7 74 16.010 3.39639 7 75 16.477 5.49586 7 76 16.552 6.21470 7 77 16.635 11.08140 ? 78 17.257 2.28673 7 79 17.318 2.82284 7 80 17.433 11.11376 7 81 17.966 2.54065 7 82 18.090 14.28333 7 [0413] 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 therefore PCT/US2008/005056 - 116- WO 2008/143749 determined 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. Thismeasurement was used to estimate the amount of coke in the Berea and subsequently how muchliquid 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 ofheating.

Example 3 [0414] 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-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, bi 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, peak4026 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 identifiedpeaks labeled with abbreviations. PCT/US2008/U05056 -117- WO 2008/143749

Table 5

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

Peak Number Ret Timermin] Area [pA*s] Compound Name נ 0.910 1.71356e4 Methane 2 0.998 341.71646 ? 3 1.076 1.5262Ie4 Ethane 4 2.534 1.7231964 Propane 5 4.242 2564.04077 iC4 6 4.919 1066.90942 7 7 5.026 6553.25244 n-Butane 8 5.299 467.88803 7 9 5.579 311.65158 7 10 6.126 33.61063 ? 11 6.374 1280.77869 iC5 12 6.737 250.05510 ? 13 6.900 2412.40918 n-Pentane 14 7.134 249.80679 ? 15 7.294 122.60424 ? 16 7.379 154.40988 ? 17 7.599 6.87471 ? 18 8.132 25.50270 ? 19 8.216 22.33015 7 20 8.339 129.17023 7 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-Hexane 26 9.551 3.05892 ? 27 9.645 25.34058 ? 28 9.708 45.14915 7 29 9.786 48.62077 7 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 ? 36 10.569 3.88067 ? 37 11.243 41.63386 ? 38 11.482 28.44063 7 39 11.558 12.05196 ? 40 11.812 37.83630 7 41 11.938 5.45990 ד 42 12.100 31.03111 ? 43 12.170 4.91053 7 44 12.301 15.75041 ? 45 12.397 13.75454 7 PCT/US2008/005056 - 118- WO 2008/143749

TableS. (Coni.)

Peak Number Ret Time[min] Area [pA*s] Compound Name 46 12.486 30.26099 7 47 12.672 15.14775 7 48 12.931 207.50433 7 49 13.064 3.35393 ? 50 13.103 3.04880 7 51 13.149 1.62203 7 52 13.198 7.97665 7 53 13.310 7.49605 ? 54 13.437 4.64921 7 55 13.519 41.82572 ? 56 13.898 19.01739 7 57 14.089 7.34498 7 58 14.316 2.68912 7 59 14,548 8.29593 7 60 14.608 3.93147 7 61 14.725 4.75483 7 62 14.869 40.93447 ? 63 14.949 5.30140 7 64 15.078 5.79979 7 65 15.134 7.95179 ? 66 15.335 1.91589 7 67 15.423 2.75893 7 68 15.515 8.64343 7 69 15.565 3.76481 7 70 15.639 3.41854 7 71 15.774 45.59035 7 72 15.850 3.73501 7 73 16.014 5.84199 7 74 16.480 4.87036 ? 75 16.555 5.12607 9 76 16.639 9.97469 7 77 17.436 8.00434 7 78 17.969 3.86749 7 79 18.093 9.71661 7 PCT/US2008/005056 - 119 * WO 2008/143749

Table 6

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

Peak Ret Time Peak Area Compound Number train] [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 nCl 1 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 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 PCT/US2008/005056 - 120- WO 2008/143749

Example 4 [0415] Conducted in a manner similar to that of Example 2 on a core specimen from oil shaleblock CM-IB; however, in this example the applied effective stress was 1,000 psi. Results for thegas 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 26,Table 7 and Table 1. In Figure 26 the y-axis 4030 represents the detector response in pico-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, peak10 4036 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) areshown 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 labeled15 with abbreviations.

Table 7

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

Peak Number Ret Timefininl 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 1.6404764 Propane 5 4.249 2286.08032 iC4 6 4.924 992.04395 ? 7 5.030 6167.50000 n-Butane 8 5.303 534,37000 ? 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 ? 15 7.136 309.94775 ? 16 7.295 154.59171 7 17 7.381 169.53279 7 18 7.555 2.80458 ? 19 7.601 5.22327 7 20 7.751 117.69164 ? 21 8.134 29.41086 ? 22 8.219 19.39338 ? 23 6.342 133.52739 ? 24 8.492 281.61343 2-methyl pentane 25 8.647 22.19704 7 26 8.882 99.56919 7 PCT/US2008/005056 - 121 - WO 2008/143749

Table 7. (Cont.)

Peak Number Ret Time[mini Area [pA*s] Compound Name 27 9.190 86.65676 ? 28 9.443 657.28754 n-Hexane 29 9.552 4.12572 ? 30 9.646 34.33701 ? 31 9.710 59.12064 ? 32 9.788 62.97972 ? 33 9.847 15.13559 ? 34 9.909 6.88310 7 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 ? 42 11.560 13.74583 7 43 11.702 2.68917 7 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 ? 51 12.584 3.27834 ? 52 12.675 14.08259 7 53 12.934 207.21574 7 54 13.105 8.29743 ? 55 13.151 2.25476 7 56 13.201 8.36965 7 57 13.312 9.49917 7 58 13.436 6.09893 7 59 13.521 46.34579 7 60 13.900 20.53506 7 61 14.090 8.41120 7 62 14.318 4.36870 7 63 14.550 8.68951 7 64 14.610 4.39150 7 65 14.727 4.35713 ? 66 14.870 37.17881 ? 67 14.951 5.78219 7 68 15.080 5.54470 7 69 15.136 8.07308 ? 70 15.336 2.07075 ? 71 15.425 2.67118 ? 72 15.516 8.47004 ? 73 15.569 3.89987 ד 74 15.641 3.96979 7 75 15.776 40.75155 ? 76 16.558 5.06379 ? 77 16.641 8.43767 7 78 17.437 6.00180 ? 79 18.095 7.66881 ? 80 15.853 3.97375 7 81 16.016 5.68997 ? 82 16.482 3.27234 7 PCT/US2008/005056 -122 ־ WO 2008/143749

Table 8

Peak and Area Details from Fig. 27 - Example 4 -1000 psi stress - Liquid GC.

Peak Number Ret Time[min] Peak AreafpA*s] Compound 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 nC18 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: 7.38l98e4 PCT/US2008/005056 - 123 - WO 2008/143749

Example 5 [0416] 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 for thegas 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[min] Area [pA*s] Compound Name 1 0.910 1.59035e4 Methane 2 0.999 434.21375 ? 3 1.077 1.5339104 Ethane 4 2.537 1.86530e4 Propane 5 4.235 2545.45850 iC4 6 4.907 1192.68970 7 7 5.015 6814.44678 n-Butane 8 5.285 687.83679 7 9 5.564 463.25885 7 ' 10 6.106 30.02624 ? 11 6.351 1295.13477 iC5 12 6.712 245.26985 7 13 6,876 2561.11792 n-Pentane 14 7.039 4.50998 ? 15 7.109 408.32999 7 16 7.268 ־ 204.45311 7 17 7.354 207.92183 7 18 7.527 4.02397 ? 19 7.574 5.65699 ? 20 7.755 2.35952 7 21 7.818 2.00382 7 22 8.107 38.23093 7 23 8.193 20.54333 ? 24 8,317 148.54445 7 25 8.468 300.31586 2-methyl pentane 26 8.622 26.06131 ? 27 8.858 113.70123 7 28 9.168 90.37163 7 29 9.422 694.74438 n-Hexane 30 9.531 4.88323 7 31 9.625 45.91505 ? 32 9.689 76.32931 9 33 9.767 77.63214 ? 34 9.826 19.23768 ? 35 9.889 8.54605 7 PCT/US2008/005056 -124- WO 2008/143749

Table 9. (Cont.)

Peak Number Ret. Time[min] Area [pA*s] Compound Name 36 9.989 37.74959 ? 37 10.204 30.83943 7 38 10.280 184.58420 ? 39 10.397 4.43609 ? 40 10.551 10.59880 ? 41 10.843 2.30370 7 42 11.231 55.64666 ? 43 11.472 35.46931 7 44 11.547 17.16440 ? 45 11.691 3.30460 ? 46 11.804 39.46368 7 47 11.931 7.32969 ? 48 12.094 30.59748 ? 49 12.163 6.93754 7 50 12.295 18.69523 ? 51 12.391 15.96837 7 52 12.482 33.66422 7 53 12.577 2.02121 7 54 12.618 2.32440 ? 55 12.670 12.83803 7 56 12.851 2.22731 ? 57 12.929 218.23195 7 58 13.100 14.33166 7 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 7 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 7 71 15.084 3.92423 ? 72 15.139 8.60328 7 73 15.340 2.17899 7 74 15.430 2.96646 7 75 15.521 9.66407 ? 76 15.578 4.27190 7 77 15.645 4.37904 7 78 15.703 2.68909 ? 79 15.782 46.97895 7 80 15.859 4.69475 7 81 16.022 7.36509 ? 82 16.489 3.91073 7 83 16.564 6.22445 7 84 16.648 10.24660 7 85 17.269 2.69753 7 86 17.445 10.16989 ? 87 17.925 2.28341 7 88 17.979 2.71101 7 89 18.104 11.19730 ? PCT/US2008/005056 * 125- WO 2008/143749

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 Ral/ton 3.63 23.4 gal/ton 3.77 21.0 gal/lon 3.02 )9.3 gal/ton 2.10 13/1 gal/ton Water (g) 0.90 2.6 gal/lon 0.30 1.7 gal/ton 0.34 1.7 gal/ton 039 2.1 gal/ton 0.28 1.5 gal/ton HCgasCg) 2.09 683 scf/ton 1.33 811 sci/ton 1.58 862 scf/ton 1.53 905 scf/ton 1.66 974 scf/ton C02(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 H2S (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) 10.91 362 gal/lon 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

Analysis [0417] 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 gassample 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.

[0418] 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 GasChromatograph 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: a) split/splitless inlet (back position of the GC)

b) FID (Flame ionization detector) back position of the GC c) HP Ultra-2 (5% Phenyl Methyl Siloxane) capillary columns (two) (25 meters x200pm ID) one directed to the FID detector, the other to an Agilent 5973 MassSelective Detector PCT/US2008/005056 -126- WO 2008/143749

d) 500μΙ fixed volume sample loop e) six-port gas sampling valve 0 cryogenic (liquid nitrogen) oven cooling capability 5 g) Oven program -80° C for 2 mins., 20°C/min. to 0°C, then 4°C/min to 20° C, then10°C/min. to 100° C, hold for 1 min. h) Helium carrier gas flow rate of 2.2ml/min. i) Inlet temperature 100° C j) Inlet pressure 19.35 psi k) Split ratio 25:1 10 1) FID temperature 310° C [0419] For non-hydrocarbon gases (e.g., argon, carbon dioxide and hydrogen sulfide) the GCconfiguration 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 15 c) GS-GasPro capillary column (30 meters x 0.32mm ID) d) 100μ1 fixed volume sample loop e) six port gas sampling valve 0 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. 20 h) Inlet temperature 200" C i) Inlet pressure 14.9 psi j) Splitless mode k) TCD temperature 250°C

[0420] For Examples 1-5, a stainless steel sample cylinder containing gas collected from the25 Parr 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 from PCT/US2008/005056 -127- WO 2008/143749 the 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.

[0421] 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.

[0422] 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 wereplotted in Chemstation to ensure good linearity (R2 &gt; 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 response PCT/US2008/005056 -128- WO 2008/143749 factor 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, 824-26 ,15-22 ,13 ,11־, and 28-78 inTable 2).

[0423] 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 Ultral 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 FID temperature set at 310 °C. Helium was used ascarrier gas at a flow of 2.1 mL min1־. Peak identifications and integrations were performed usingChemstation software Rev.A.10.02 [1757] (Agilent Tech. 1990-2003) supplied with the Agilentinstrument.

[0424] 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, autosamplerand 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. PCT/US2008/005056 ־129- WO 2008/143749 [0425] 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-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.

[0426] 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.

[0427] 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 asdescribed 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" PCT/US2008/005056 -130- WO 2008/143749 of 8209.22 pAs g/ml. Similarly, the integration areas for each pseudo component and all lighterlisted compounds (i.e., nC3, iC4, nC4, iCS &amp;amp; nC5) are determined and multiplied by theirrespective 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) is5 then 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 bysuch components or compounds respective molecular weight to yield an "area X density /molecular weight" number for each respective pseudo component and listed compound. The10 respective 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 pAsmol/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 "total15 area X density / molecular weight" number (665.28 pAs mol/ml) to obtain the CIO pseudocomponent molar percentage of 9.21 molar percent. PCT/US2008/005056 -131 WO 2008/143749

Table 10

Pseudo-Components for Example 1 - GC of Liquid - 0 Stress

Component Area (cts.) Area * Avg. BollingPL (“FI Density (giinl) MolecularWL (g/mol) WL % Mol % nC1 41.881 0.03 -43.73 0.5069 44.10 0.02 0.07 1C, 120.873 0.10 10.94 0.5628 58.12 0.07 0.18 flCj 805.690 0.66 31.10 0.5840 58.12 0.49 1.22 —icf— 1092.699 0.89 82.13 0.6244 72.15 0.71 1.42 nC, 2801.815 2.29 96.93 0.6311 72.15 1.84 3.68 Pseudo CA 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 C! 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 Cm 10551.700 8.61 330.50 0.7780 134.00 8.53 9.21 Pseudo Cl! 9274.333 7.57 369.00 0.7890 147.00 7.60 7.48 Pseudo C״ 8709.231 7.11 407.00 ר 0.8000 161.00 7.24 6.50 Pseudo Cn 7494.549 6.12 441.00 0.8110 175.00 6.31 5.22 Pseudo Cm 6223.394 5.08 475.50 0.8220 190.00 5.31 4.05 Pseudo Cm 6000.179 4.90 511.00 0.8320 206.00 5.19 3.64 Pseudo Cm 5345.791 4.36 542.00 0.8390 222.00 4.66 3.04 Pseudo C!7 4051.886 3.31 572.00 0.8470 237.00 3.57 2.18 Pseudo Cm 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 C50 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 C71 1173.834 0.96 707.00 0.8770 318.00 1.07 0.49 Pseudo C74 822.762 0.67 727.00 0.8810 331.00 0.75 0.33 Pseudo Cy 677.938 0.55 747.00 0.8850 345.00 0.62 0.26 Pseudo C21t 532.788 0.43 766.00 0.8890 359.00 0.49 0.20 Pseudo C!7 459.465 0.38 784.00 0.8930 374.00 0.43 0.16 Pseudo C2s 413.397 0.34 802.00 0.8960 388.00 0.38 0.14 Pseudo Cm 522.898 0.43 817.00 0.8990 402.00 0.49 0.18 Pseudo C!o 336.968 0.28 834.00 0.9020 416.00 0.32 0.11 Pseudo Cn 322.495 0.26 850.00 0.9060 430.00 0.30 0.10 Pseudo C72 175.615 0.14 866.00 0.9090 444.00 0.17 0.05 Pseudo Cn 165.912 0.14 881.00 0.9120 458.00 0.)6 0.05 Pseudo Cm 341.051 0.28 895.00 0.9140 472.00 0.32 0.10 Pseudo Cn 286.861 0.23 908.00 0.9170 486.00 0.27 6.08 Pseudo Cn 152.814 0.12 922.00 0.9190 500.00 0.15 0.04 Pseudo Cn 356.947 0.29 934.00 0.9220 514.00 0.34 0.10 Pseudo Cn 173.428 0.14 947.00 0.9240 528.00 0.17 0.05 Totals 122484.217 100.00 100.00 100.00 PCT/US2008/005056 - 132- WO 2008/143749

Table Π

Pseudo-Components for Example 3 - GC of Liquid - 400 psi stress

Component Area Area% Avg. BollingPtCF) Density (R/ml) Molecular WL(e/moll Wt% Mol % Λ C! 35.845 0.014 -43.730 0.5069 44.10 0.01 0.03 -ic.- 103.065 0.041 10.940 0.5628 58.12 0.03 0.07 nCi 821.863 0.328 31.100 0.5840 58.12 0.24 0.62 -icT- 1187.912 0.474 82.130 0.6244 72.15 0.37 0.77 ״c, 3752.655 1.498 96.930 0.6311 72.15 1.20 2.45 Pseudo C* 12040.900 4.805 147.000 0.6850 84.00 4.17 7.34 Pseudo C, 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 12Γ.00 9.77 11.94 Pseudo C1a 22640.400 9.035 330.500 0.7780 134.00 8.90 9.82 Pseudo Cn 20268.100 8.089 369.000 0.7890 147.00 8.08 8.13 ל! Pseudo C 18675.600 7.453 407.000 0.8000 161.00 7.55 6.93 ל! Pseudo C 16591.100 6.621 441.000 0.8110 175 00 6.80 5.74 Pseudo Cu 13654.000 5.449 475.500 0.8220 190.00 5.67 4.41 Pseudo Cn 13006.300 5.191 511.000 0.8320 206.00 5.47 3.92 Pseudo Cut 11962.200 4.774 542.000 0.8390 222.00 5.07 3.38 Pseudo C״ 8851.622 3.533 572.000 0.8470 237.00 3.79 2.36 Pseudo Cn 7251.438 2.894 595.000 0.8520 251.00 3.12 1.84 Pseudo C!q 5946.166 2.373 617.000 0.8570 263.00 2.57 1.45 Pseudo C20 4645.178 1.854 640.S00 0.8620 275.00 2.02 1.09 Pseudo C3i 4188.168 1.671 664.000 0.8670 291-00 1.83 0.93 Pseudo C51 2868.636 1.145 686.000 0.8720 305.00 1.26 0.61 Pseudo €לל 2188.895 0.874 707.000 0.8770 318.00 0.97 0.45 Pseudo Cm 1466.162 0.585 727.000 0.8810 331.00 0.65 0.29 Pseudo 1181.133 0.471 747.000 0.8850 345.00 0.53 0.23 Pseudo Cm 875.812 0.350 766.000 0.8890 359.00 0.39 0.16 Pseudo Cn 617.103 0.246 784.000 0.8930 374.00 0.28 0.11 Pseudo Cm 538.147 0.215 802.000 0.8960 388.00 0.24 0.09 Pseudo Cn 659.027 0.263 817.000 0.8990 402.00 0.30 0.11 Pseudo C30 1013.942 0.405 834.000 0.9020 416.00 0.46 0.16 Pseudo C״ 761.259 0.304 850.000 0.9060 430.00 0.35 0.12 Pseudo Cn 416.031 0.166 866.000 0.9090 444.00 0.19 0.06 Pseudo Cm 231.207 0.092 881.000 0.9120 458.00 0.11 0.03 Pseudo Cu 566.926 0.226 895.000 0.9140 472.00 0.26 0.08 Pseudo Cm 426.697 0.170 908.000 0.9170 486.00 0.20 0.06 Pseudo Cm 191.626 0.076 922.000 0.9190 500.00 0.09 0.03 Pseudo Cn 778.713 0.311 934.000 0.9220 514.00 0.36 0.10 Pseudo Cm 285.217 0.114 947.000 0.9240 528.00 0-13 0.04 Totals 250574.144 100.000 100.00 100.00 PCT/US2008/005056 133־ WO 2008/143749

Table 12

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

Component Area Area % Avg. BollingPLCF) Density teftul) Molecular Wl(g/mol) Wt.% Mol % nCi 44.761 0.023 -43.730 0.5069 44.10 0.01 0.05 1C4 117.876 0.060 10.940 0.5628 58.12 0.04 0.11 nCi 927.866 0.472 31.100 0.5840 58.12 0.35 0.87 iC, 1082.570 0.550 82.130 0.6244 72.15 0.44 0.88 nCt 3346.533 1.701 96.930 0.6311 72.15 1.37 2.74 Pseudo C* 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 PseudoC* 19693.300 10.012 242.000 0.7450 107.00 9.48 12.83 PseudoC* 20326.300 10.334 288.000 0.7640 121.00 10.04 12.01 Pseudo Cm 18297.600 9202 330.500 0.7780 134.00 9.20 9.94 Pseudo C11 16385.600 8.330 369.000 0.7890 147.00 8.36 8.23 Pseudo C!7 15349.000 7.803 407.000 0.8000 161.00 7.94 7.14 Pseudo Cm 13116.500 6.668 441.000 0.8110 175.00 6.88 5.69 Pseudo Cu 10816.100 5.499 475.500 0.8220 190.00 5.75 4.38 Pseudo Cu 10276.900 5.225 511.000 0.8320 206.00 5.53 3.88 Pseudo Cm 9537.818 4.849 542.000 0.8390 222.00 5.17 3.37 Pseudo Cm 6930.611 3.523 572.000 0.8470 237.00 3.79 2.32 Pseudo C» 5549.802 2.821 595.000 0.8520 251.00 3.06 1.76 Pseudo Cm 4440.457 2.257 617.000 0.8570 263.00 2.46 1.35 Pseudo Cm 3451250 1.755 640.500 0.8620 275.00 1.92 1.01 Pseudo Cu ׳ 3133251 1.593 664.000 0.8670 291.00 1.76 0.87 Pseudo Cm 2088.036 1.062 686.000 0.8720 305.00 1.18 0.56 Pseudo Cm 1519.460 0.772 707.000 0.8770 318.00 0.86 0.39 Pseudo C71 907.473 0.461 727.000 0.8810 331.00 0.52 0.23 Pseudo C:&lt; 683.205 0.347 747.000 0.8850 345.00 0.39 0.16 Pseudo C7a 493.413 0.251 766.000 0.8890 359.00 0.28 0.11 Pseudo Cn 326.831 0.166 784.000 0.8930 374.00 0.19 0.07 Pseudo C7r 272.527 0.139 802.000 0.8960 388.00 0.16 0.06 Pseudo Cm ׳ 291.862 0.148 817.000 0.8990 402.00 0.17 0.06 Pseudo Cn 462.840 0.235 834.000 0.9020 416.00 0.27 0.09 Pseudo C71 352.886 0.179 850.000 0.9060 430.00 0.21 0.07 Pseudo Cm 168.635 0.086 866.000 0.9090 444.00 0.10 0.03 Pseudo Cm 67.575 0.034 881.000 0.9120 458.00 0.04 0.01 Pseudo Cu 95.207 0.048 895.000 0.9140 472.00 0.06 0.02 Pseudo Cm 226.660 0.115 908.000 0.9170 486.00 0.13 0.04 Pseudo Cm 169.729 0.086 922.000 0.9190 500.00 0.10 0.03 Pseudo Cn 80.976 0.041 934.000 0.9220 514.00 0.05 0.01 Pseudo Cm 42.940 0.022 947.000 0.9240 528.00 0.03 0.01 Totals 196699.994 100.000 100.00 100.00 [0428] TOC and Rock-eval tests were performed on specimens from oil shale block CM-IB5 taken at the same stratigraphic interval as the specimens tested by the Parr heating method described in Examples 15־. These tests resulted in a TOC of 21% and a Rock-eval HydrogenIndex of 872 mg/g־toc.

[0429] 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 in 10 Table 13. PCT/US2008/005056 -134- WO 2008/143749 [0430] 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 II instrument.Rock samples were crushed, micronized, and air-dried before loading into Rock-Eval crucibles. 5 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 IFP 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 with 10 samples. The standard was also run before and after every 10 samples to monitor theinstrument's performance.

[0431] 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. After 15 introduction 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 (FID)yielding the S! peak. The pyrolysis-oven temperature was then increased at a gradient of25pC/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. 20 [0432] Hydrogen Index (HT) is calculated by normalizing the S2 peak (expressed as ׳nghydrocarbonJgrock) to weight % TOC (Total Organic Carbon determined independently) asfollows:

HI = {S2/TOC)*lOO where HI is expressed as mghydmcarbon/girx 25 [0433] Total Organic Carbon (TOC) was determined by well known methods suitable for geological samples - 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 form ofC02.

Table 13 30 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 (mR/R-toc) 77 83 81 62 77 PCT/US2008/005056 -135 ־ WO 2008/143749 [0434] The API gravity of Examples 15־ was estimated by estimating the room temperaturespecific gravity (SG) of the liquids collected and the results are reported in Table 14. The APIgravity was estimated from the determined specific gravity by applying the following formula: API gravity =(141.5/SG)-131.5 5 [0435] The specific gravity of each liquid sample was estimated using the following procedure. An empty 50 μΐ 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 subtracting10 the loaded syringe measured weight from the measured empty syringe weight. The specificgravity 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 Examples API Gravity 29.92 30.00 27.13 32.70 30.00 [0436] The above-described processes may be of merit in connection with the recovery ofhydrocarbons 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 persurface acre. One study has estimated the oil shale resource within the nahcolite-bearing portions 20 of the oil shale formations of the Piceance Basin to be 400 billion banels of shale oil in place.Overall, up to 1 trillion barrels of shale oil may exist in the Piceance Basin alone.

[0437] Certain features of the present invention are described in terms of a set of numericalupper 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. 25 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 independentclaim or claims.

[0438] While it will be apparent that the invention herein described is well calculated to30 achieve the benefits and advantages set forth above, it will be appreciated that the invention is susceptible to modification, variation and change without departing from the spirit thereof. ;משפטים ה ודנו העתק שנסדק בשלמותו ביום ובשנה המצוינים; ממוחשבת מהימנה מהמסמך המצוי בתיק,לנוהל הבדיקות במשרד המשפטים.וס ;שרד המשפטים(חתימה מוסדית).