CA2407215A1

CA2407215A1 - Method and system for treating a hydrocarbon containing formation

Info

Publication number: CA2407215A1
Application number: CA002407215A
Authority: CA
Inventors: Ilya Emil Berchenko; Robert Martijn Van Hardeveld; John Michael Karanikas; Charles Robert Keedy; Kevin Albert Maher; Eric De Rouffignac; Robert Charles Ryan; Lanny Gene Schoeling; Gordon Thomas Shahin; George Leo Stegemeier; Harold J. Vinegar; Scott Lee Wellington; Etuan Zhang; John Matthew Coles; Thomas David Fowler; Ajay Madhav Madgavkar; James Louis Menotti; Bruce Gerard Hunsucker; Lawrence James Bielamowicz
Original assignee: Individual
Current assignee: Shell Canada Ltd
Priority date: 2000-04-24
Filing date: 2001-04-24
Publication date: 2001-11-01
Also published as: WO2001081720A1; ATE276427T1; AU5481501A; US20020038069A1; WO2001081716A2; US20020053435A1; IL152455A0; EA200201132A1; US20020132862A1; CN1430698A; US6581684B2; WO2001081239A3; US20020036083A1; US6805195B2; US6732794B2; CA2407022C; US20020096320A1; US6732795B2; EP1276960B1; US6736215B2

Abstract

A method is disclosed for treating a hydrocarbon containing formation in sit u and producing a hydrocarbon fluid from the formation, which method comprises pyrolysing hydrocarbons present in the formation during the production of th e hydrocarbon fluid from the formation with the application of a pressure/temperature control such that the pressure is at least the pressure which can be calculated for a selected temperature, or the temperature is at most the temperature which can be calculated for a selected pressure from th e equation (I) wherein P is pressure (bar absolute), T is temperature (~C), an d A and B are predetermined parameters which relate to a property which is relevant to the quantity, the composition or the quality of the hydrocarbon fluids produced. Optionally, the method is followed by the step of in-situ producing synthesis gas, which step comprises providing a partly depleted hydrocarbon containing formation which is treated according to the said meth od for treating a hydrocarbon containing formation in-situ, and reacting the hydrocarbon containing formation with a synthesis gas generating fluid. Optionally the synthesis gas so produced is converted into hydrocarbons; and/or energy is generated by expanding and/or combusting the synthesis gas so produced or using the synthesis gas so produced in a fuel cell.

Description

DEMANDES OU BREVETS VOLUMINEUX
LA PRESENTE PARTIE I)E CETTE DEMANDE OU CE BREVETS
COMPREND PLUS D'UN TOME.
CECI EST LE TOME DE _2 NOTE: Pour les tomes additionels, veillez contacter le Bureau Canadien des Brevets.

JUMBO APPLICATIONS / PATENTS

THIS SECTION OF THE APPLICATION / PATENT CONTAINS MORE
THAN ONE VOLUME.

NOTE: For additional volumes please contact the Canadian Patent Office.

METHOD AND SYSTEM FOR TREATI:NG A HYDROCARBON CONTAINING
FORMATION

The invent.:~-on relates to a method and system for treating a hyd;_ocarbon containing formation in situ and producing a hydrocarbon fluid from the formation, by pyrolysing hyd~ocarbons prese.nt in the formation.
Hydrocarbons obtairied from subterranean formations are often used 4rs energy resources, as feedstocks, and as consumer produc.t:s. Concerris over depletion of available hydrocarbon resources have led to development of processes for more efficient recovery, processing and use of available hydrocarbori resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon ma-.erial within a subterranean formation may Izeed to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. Th2! chemical and physical changes may include in situ reactions that produce removable fluids, solubility chaizcies, phase changes, and/or viscosity changes of the hydrocarbon material within the formation.
A fluid may be, Jout is not l.imited to, a gas, a liquid, an emulsion, a slurry and/or a stream of solid particles that has flow characteristics similar to liquid flow.

Examples of in situ processes utilizing downhole heaters are illustrated ir: U;;-A-2634961, US-A-2732195, US-A-2780450, 13S--A-2789805, ;:;rS-A-2923535, US-A-4886118, US-A-2914309, US-A-4344483, CIS-A-4067390, US-A-4662439 and US-A-4384613.

- la -For example, the application of heat to oil shale formations is c:;:escribed in US-A-2923535 and US-A-4886118.

Herein, heat is applied to the oil shale formation to pyrolyse kerogen within the oil shale formation. The heat also fractures the formation to increase permeability of the formation. The increased permeability allows hydrocarbon fluids to travel to a production well where the fluid is removed from the oil shale formation. In US-A-2923535 pressure was applied by closing all gas outlet valves for the purpose of testing the formation's porosity and permeability for gases and vapours. US-A-2923535 is silent about maintaining an elevated pressure during the production of gases and vapours.
There has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations.

It has now been found that the quantity, the composition and the quality of the hydrocarbon fluid produced in the pyrolysis can be controlled by controlling the pressure in relation to the applied temperature and vice versa. In this respect the quantity, the composition and the quality of the hydrocarbon fluids may be defined by one or more relevant properties, such as API gravity, olefin to paraffin ratio, elemental carbon to hydrogen ratio, equivalent liquids produced (gas and liquid), liquids produced, percent of Fischer Assay and the presence of hydrocarbons with carbon numbers greater than 25 within the hydrocarbon fluids. The pressure for a selected temperature, or the temperature for a selected pressure, which may yield hydrocarbon fluids having the relevant property may be determined using an equation, i.e.
"equation 1" hereinafter, of the form:

-A
+ B
P= 0. 07 * e T+ 273 wherein P is the pressure (bar absolute), T is the temperature ( C), and A and B are parameters which relate to the relevant property and which can be determined by experiment. The dimensions of the factor 0.07 and the parameters A and B are such as to comply with the dimensions of P and T.

In many cases, the application of the temperature/pressure control will involve to the application of an elevated pressure during the pyrolysis.
It has appeared that the application of an elevated pressure has a number of unexpected advantages. These advantages apply independently of the application of the present temperature/pressure control.
An elevated pressure in the formation results in the production of improved hydrocarbon fluids. As pressure within the formation is increased, hydrocarbon fluids produced from the formation include a larger portion of non-condensable components. In this manner, a significant amount (e.g., a majority) of the hydrocarbon fluids produced at such a pressure includes a lighter and higher quality condensable component than hydrocarbon fluids produced at a lower pressure.

Maintaining an elevated pressure within the heated formation has been found to substantially inhibit production of hydrocarbon fluids having carbon numbers 611 UU U!. IIUlS 14.1J !=lt/l J1 IU JI IU141 1!' ~6AYll.tS.1 lgj U

~ 4 -greater than, for ezcample, about 25 and/or mult~-ring hydrocarbon compounds. It also appeared that maintaining an elevated pressure within the heated formation results in an increase in API gravity of hydrocarbon fluids produced from the forrnation. Thus, higher pressures may increase production of relatively short chain hydrocarbon fluids, which may have h,igher API gravity values. ' Further, maintaining an elevated pressure within the formation inhibits format,ion subsidence. Maintaining an elevated pressure within the formation also tends to reduce the required sizes of collection conduits which are used to transport condensable components.
Maintaining an elevated within the formation may also facilitate generation of electricity from produced non-condensable fluid. For example, the produced non-condensable flu~d may be passed through a turbine to generate electzicity.
Accordingly, the present 9.avention provides a method for treating a hydrocarbon containing formation in situ and producing a hydrocarbon fluid fxom the formation, which method comprises pyrolysing hydrocarbons present in the formation during the production of the hydrocarbon fluid from the formation with the application of a pressure/temperature contrvl such that the pressure is at least the pressure which can be calculated for a selected temperature, or the temperature is at most the temperature which can be calculated for a selected pressure from the equation - A +
P ;-- 0.07*eT+273 wherein P is pressure (bar absolute), T is temperature ( C), and A and B are predetermined parameters and wherein A is at least 5000, 6 is at least 10 and P is at AMENDED SHEET

most 72 bar absolute to control a property which is relevant to the quantity, the composition or the quality of the hydrocarbon fluids produced.

In one aspect, the invention provides a method for treating a hydrocarbon containing formation in situ and producing a hydrocarbon fluid from the formation, which method comprises pyrolysing hydrocarbons present in the formation during the production of the hydrocarbon fluid from the formation with the application of a pressure/temperature control; wherein the pressure is at least the pressure which is calculated for a selected temperature, or the temperature is at most the temperature which is calculated for a selected pressure from the equation:

- A
P=0.07*eT+273+B
wherein P is pressure, bar absolute, T is temperature, C, and A and B are predetermined parameters, and wherein the value of A is in the range of from 5,000 up to 60,000, B is from 10 up to 90, and P is at most 72 bar absolute to control a property which is relevant to the quantity, the composition, the quality or both of the hydrocarbon fluids produced; and wherein a heat source is applied, which is configured for heating the hydrocarbon formation substantially by conductive heating.

The invention also provides a system of heat injection and hydrocarbon fluid production wells for use in the method according to the invention and pyrolysis products having a low olefin content (e.g. <10% by weight) and low average carbon number (e.g. <35) which are obtainable by the in-situ pyrolysis method and system according to the invention.

- 5a -The invention also provides a method for producing synthesis gas which method comprises providing a hydrocarbon containing formation which is treated by the method according to this invention and reacting the hydrocarbon containing formation with a synthesis gas generating fluid.
The invention also provides a method for converting the thus produced synthesis gas into hydrocarbons.

The invention also provides a method of producing energy by expanding and/or combusting the thus produced synthesis gas.

IL is observed LhaL US A-4, 662, 439 discloses a method of underground conversion of coal, wherein an oxyger-containing gas and steam is injected into a coal bed which is rubbled by explosives to generate a syngas, which converts as much as 90 wt% of moisture and ash-free (MAF) coal into liquid and qaseous products if high pressure (4000-5000 psig ~ 275-350 bar absolute) is maintained and the temperature is about 550 C.

US-A-5236039 discloses a method for the in situ treatment of a hydrocarbon containing formation, using radio frequency heating sources for heating the formation to pyrolysis temperature. In this document there is no generic teaching with respect to the influence of pressure on the method or its results. However, there is an incidental disclosure of 50 psi in combination with pyrolysis temperatures up to 575 F in relation to a simulation of the invention concerned (cf. Table 1 therein). The application in the treating method of the invention of a pressure of 3.52 bar (50 psi) at temperatures up to 301.7 C (575 F) in combination with application of radio frequency heating is excluded from the protection of certain embodiments c,f this invention.
Unless indicated otherwise, the term "pressure" is herein deemed to refer to absolute pressure. The temperature and pressure prevailing during the production of hydrocarbon fluid from the formation or during synthesis gas generation is deemed to be measured in a production well, in the direct proximity of the relevant portion of the formation where pyrolysis or synthesis gas production takes place. The pressure thus substantially corresponds to a pore pressure in the formation in the region where the pyrolysis takes place. Instead of measuring the temperature, the temperature may be assessed on the basis of the heat input generated by the heater wells and the heat generated and/or consumed by the pyrolysis and/or other reaction(s) and the properties of the formation.

Preferably the hydrocarbon containing formation for use in this invention contains kerogen. Kerogen is composed of organic matter which has been transformed due to a maturation process. Hydrocarbon containing formations which include kerogen are for example coal containing formations and oil shale containing formations. Preferably, the kerogen has a vitrinite reflectance of 0.2% to 3%, preferably above 0.25% and more preferably above 0.4% and preferably below 2% and more preferably below 1.2% and/or a hydrogen content of at least 2 wt%, preferably at least 3 wt%. Alternatively, hydrocarbon containing formations may be treated which do not include kerogen, for example, formations containing heavy hydrocarbons (e.g., tar sands).

Hydrocarbon containing formations may be selected for in situ treatment based on properties of at least a portion of the formation such that it leads to the production of high quality fluids from the formation.
For example, hydrocarbon containing formations which include kerogen may be assessed or selected for treatment based on the vitrinite reflectance of the kerogen.

Vitrinite reflectance is often related to the elemental hydrogen to carbon ratio of a kerogen and the elemental oxygen to carbon ratio of the kerogen. Preferably the vitrinite reflectance is in the range of from 0.2% to 3.0%, more preferably from 0.5% to 2.0%. Such ranges of vitrinite reflectance tend to indicate that relatively higher quality hydrocarbon fluids will be produced from the formation.

The hydrocarbon containing formation may be selected for treatment based on the elemental hydrogen content of the hydrocarbon containing formation. For example, a method of treating a hydrocarbon containing formation may typically include selecting a hydrocarbon containing formation for treatment having an elemental hydrogen content greater than 2 weight %, in particular greater than 3 weight %, or more in particular greater than 4 weight % when measured on a dry, ash-free basis.
Preferably, the hydrocarbon containing formation has an elemental hydrogen to carbon ratio in the range of from 0.5 to 2, in particular from 0.70 to 1.7. The elemental hydrogen content may significantly affect the composition of hydrocarbon fluids produced, for example through the formation of molecular hydrogen. Thus, if too little hydrogen is present in the formation, then the amount and quality of the produced fluids will be negatively affected. It is advantageous to maintain a hydrogen partial pressure and if too little hydrogen is naturally present, then hydrogen or another reducing fluid may be added to the formation.
The formation may typically have an elemental oxygen weight percentage of less than 20%, in particular less than 15 %, and more in particular less than 10% when measured on a dry, ash-free basis. Typically, the elemental oxygen to carbon ratio is less than 0.15. In this manner, production of carbon dioxide and other oxides from an in situ conversion process of hydrocarbon containing material may be reduced. Frequently, the elemental oxygen to carbon ratio is in the range of from 0.03 to 0.12.

Heating the hydrocarbon containing formation generally includes providing a large amount of energy to heat sources located within the formation. Hydrocarbon containing formations may contain water. Water present in the hydrocarbon containing formation will tend to further increase the amount of energy required to heat the hydrocarbon containing formation, because a large amount of energy may be required to evaporate water from the formation. Therefore, excessive amounts of heat and/or time may be required to heat a formation having a high moisture content. Preferably, the water content of the hydrocarbon containing formation is less than 15 weight %, more preferably less than 10 weight %.

The hydrocarbon containing formation or the portion thereof which is subjected to pyrolysis may have a width of for example at least 0.5 m, or at least 1.5 m, or at least 2.4 m, or even at least 3.0 m. The width may be up to 100 m, or up to 1000 m, or even up to 2000 m, or more.

- 9 -.

The hydrocarbon containing formation or the portion thereof which is subjected to pyrolysis may have a layer thickness of, for example, at least 2 m, more typically in the range of from 4 m to 100 m, more typically from 6 m to 60 m. The overburden of the hydrocarbon containing formation may have a thickness of, for example, at least 10 m, more typically in the range of from 20 m to 800 m or to 1000 m or more.
The hydrocarbon containing formation may be heated according to methods known in the art to a temperature sufficient for pyrolysis of hydrocarbons present in the formation, by using one or more heat sources placed in heater wells.

The heater wells may be positioned in the proximity of, or preferably within the hydrocarbon containing formation. Preferably a plurality of heat sources is employed so that a large portion of a hydrocarbon containing formation may be heated, and preferably such that superposition (overlapping) of heat produced from the heat sources occurs. Superposition of heat may decrease the time necessary to reach pyrolysis temperatures. Superposition of heat may allow for a relatively large spacing between adjacent heat sources, which may in turn provide a relatively slow rate of heating of the hydrocarbon containing formation.
Superposition of heat will also provide uniform heating so that temperatures can be controlled to generate fluids with desirable properties throughout (a large portion) of the heated portions of the hydrocarbon containing formation.

The spacing between heat sources may typically be within the range of from 5 m to 20 m, preferably from 8 m to 12 m. Positioning of equidistant heat sources, in a triangular pattern, is preferred as it tends to provide more uniform heating to the formation in comparison to other patterns such as hexagons. In addition, a triangular pattern tends to provide faster heating to a predetermined temperature in comparison to other patterns such as hexagons.

Any conventional heat source may be applied. It is preferred to apply heat sources which are suitable for conductive heating, for example any kind of electrical heater or any kind of combustion heater. Less preferred are heat sources which apply radio frequency heating.
Because permeability and/or porosity are relatively quickly increased in the heated formation, produced vapours may flow considerable distances through the formation with relatively little pressure differential.
Increases in permeability result from a reduction of mass of the heated portion due to evaporation of water, removal of hydrocarbons, and/or creation of fractures.
For the recovery of the hydrocarbon fluids, production wells may be provided, preferably near the upper surface of the formation. Fluid generated within the hydrocarbon containing formation may move a considerable distance through the hydrocarbon containing formation as a vapour.
Such a considerable distance may include, for example, 50 m to 1000 m. The vapour may have a relatively small pressure drop across the considerable distance due to the permeability of the heated portion of the formation. Due to such permeability, a production well may only need to be provided in every other unit of heat sources or every third, fourth, fifth, sixth units of heat sources, which each may comprise a plurality of heater wells, for example two, three or six. The production wells may be cased wells which may have a production screen or perforated casings. In addition, the production wells may be surrounded by sand or gravel to minimize the pressure drop of fluids entering the casing.

In addition, water pumping wells or vacuum wells may be configured to remove liquid water from the hydrocarbon containing formation. For example, a plurality of water wells may surround all or the portion of the formation to be heated.

The hydrocarbon fluid produced is a material which contains carbon and hydrogen in its molecular structure.
It may also include other elements, such as halogens, metallic elements, nitrogen, oxygen and sulphur.

The hydrocarbon containing formation is heated to a temperature at which pyrolysis can take place. The pyrolysis temperature range may include temperatures up to, for example, 900 C. A majority of hydrocarbon fluids may be produced within a pyrolysis temperature range of from 250 C to 400 C, more preferably in the range of from 260 C to 375 C. A temperature sufficient to pyrolyse heavy hydrocarbons in a hydrocarbon containing formation of relatively low permeability may be within a range from 270 C to 300 C. In other embodiments, a temperature sufficient to pyrolyse heavy hydrocarbons may be within a range from 300 C to 375 C.

If a hydrocarbon containing formation is heated throughout the entire pyrolysis temperature range, the formation may produce only small amounts of hydrogen towards the upper limit of the pyrolysis temperature range. After the available hydrogen is depleted, little hydrocarbon production from the formation may occur.
Preferably, the hydrocarbon containing formation or the portions thereof designated for pyrolysis is heated at a low heating rate. In general the heating rate will be at most 50 C/day. Typically, the heating rate is less than 10 C/day, more typically less than 3 C/day, in particular less than 0.7 C/day. Frequently the rate of heating will be more than 0.01 C/day, in particular more than 0.1 C/day. In particular, such low heating rates are applied in the pyrolysis temperature range.
More in particular, heated portions of the hydrocarbon containing formation may be heated at such a rate for a time greater than 50% of the time needed to span the pyrolysis temperature range, preferably more than 75% of the time needed to span the pyrolysis temperature range, or more preferably more than 90% of the time needed to span the pyrolysis temperature range.

The rate at which a hydrocarbon containing formation is heated may affect the quantity and quality of the hydrocarbon fluids produced from the hydrocarbon containing formation. For example, heating at high heating rates may produce a larger quantity of fluids from a hydrocarbon containing formation. The products of such a process, however, may be of a significantly lower quality than when heating using lower heating rates.
Further, controlling the heating rate at less than 3 C/day generally provides better control of the temperature within the hydrocarbon containing formation.
The present teachings as regards heating rates are applicable independent of the application of the temperature/pressure control of this invention.

Heating of a hydrocarbon containing formation to the pyrolysis temperature range may occur before substantial permeability has been generated within the hydrocarbon containing formation. An initial lack of permeability may prevent the transport of generated fluids from a pyrolysis zone within the formation. In this manner, as heat is initially transferred from the heat source to the hydrocarbon containing formation, the fluid pressure within the hydrocarbon containing formation may increase proximate to the heat source.

The pressure generated by expansion of the hydrocarbon fluids or other fluids generated in the formation may initially increase as an open path to the production well or any other pressure sink may not yet exist in the formation. In addition, the fluid pressure may exceed the lithostatic pressure, so that fractures in the hydrocarbon containing formation may form from the heat sources to the production wells. The generation of fractures within the heated portion then reduces the pressure, due to the production of hydrocarbon fluids through the production wells.

To maintain pressure within the carbon containing formation during the production of hydrocarbon fluids, a back pressure may be maintained at the production well.
The pressure may be controlled by means of valves and/or by injecting gases into the hydrocarbon containing formation, for example hydrogen, carbon dioxide, carbon monoxide, nitrogen or methane, or water or steam.
Injecting hydrogen is particularly preferred.
Valves may be configured to maintain, alter, and/or control the pressure within the hydrocarbon containing formation. For example, heat sources disposed within the hydrocarbon containing formation may be coupled to a valve. The valve may be configured to release fluid from the formation through the heat source or for the injection of a gas into the hydrocarbon containing formation. Alternatively, a pressure valve may be coupled to the production wells. Fluids released by the valves may be collected and transported to a surface unit for further processing and/or treatment.
In accordance with this invention the pressure and the temperature are controlled during pyrolysis and during the production of the pyrolysed hydrocarbon fluid from the formation, in order to achieve control of certain properties which are relevant to the quantity, the composition and the quality of the hydrocarbon fluids. The value of the parameters A and B in equation 1 can be determined by experiment. Generally, values of the parameter A may be in the range of from 5000 up to 60000 and values of the parameter B may be in the range of from 10 up to 90. Some examples are given hereinafter.

For producing a pyrolysed hydrocarbon fluid having a low content of hydrocarbons having a carbon number of 25 or more, for example less than 25 weight %, it is preferred that the pressure is at least the pressure which can be calculated for a selected temperature, or the temperature is at most the temperature which can be calculated for a selected pressure from equation 1 wherein A equals about 14000 and B equals about 25.
Preferably A equals 14206 and B equals 25.123, more preferably A equals 15972 and B equals 28.442, in particular A equals 17912 and B equals 31.804, more in particular A equals 19929 and B equals 35.349, most in particular A equals 21956 and B equals 38.849. In practice it may frequently be sufficient that the pressure is at most the pressure which can be calculated for a selected temperature, or the temperature is at least the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 24146 and B equals 43.349.

For producing a hydrocarbon fluid of which the condensable hydrocarbons have a high API gravity, for example at least 30 , it is preferred that the pressure is at least the pressure which can be calculated for a selected temperature, or the temperature is at most the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 30864 and B
equals 50.676, more preferably A equals 21719 and B
equals 37.821, in particular A equals 16895 and B equals 31.170. In practice it may frequently be sufficient that the pressure is at most the pressure which can be calculated for a selected temperature, or the temperature is at least the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 16947 and B equals 33.603. As used herein, "condensable hydrocarbons" are hydrocarbons which have a boiling point of at least 25 C at 1 bar.

For producing a hydrocarbon fluid having a low ethylene/ethane ratio, for example at most 0.1, it is preferred that the pressure is at least the pressure which can be calculated for a selected temperature, or the temperature is at most the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 57379 and B equals 83.145, more preferably A equals 16056 and B equals 27.652, in particular A equals 11736 and B equals 21.986. In practice it may frequently be sufficient that the pressure is at most the pressure which can be calculated for a selected temperature, or the temperature is at least the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 5492.8 and B equals 14.234.

For producing a hydrocarbon fluid of which the condensable hydrocarbons have a high elemental hydrogen to carbon ratio, for example at least 1.7, it is preferred that the pressure is at least the pressure which can be calculated for a selected temperature, or the temperature is at most the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 38360 and B equals 60.531, more preferably A equals 12635 and B equals 23.989, in particular A equals 7953.1 and B equals 17.889. In practice it may frequently be sufficient that the pressure is at most the pressure which can be calculated for a selected temperature, or the temperature is at least the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 6613.1 and B equals 16.364.

The total potential amount of hydrocarbon fluids which may be produced from the hydrocarbon containing material may be determined by the Fischer Assay. The Fischer Assay is a standard method which involves heating a sample of hydrocarbon containing material to approximately 500 C, collecting products produced from the heated sample, and quantifying the products. For producing a high quantity of hydrocarbon fluid from the hydrocarbon containing formation, for example at least 60% of the value indicated by the Fischer Assay, it is preferred that the pressure is at most the pressure which can be calculated for a selected temperature, or the temperature is at least the temperature which can be calculated for a selected pressure to apply a pressure which is at most the pressure (or to apply a temperature which is at least the temperature) which can be calculated from equation 1 wherein A equals 11118 and B

equals 23.156, more preferably A equals 13726 and B
equals 26.635, in particular A equals 20543 and B equals 36.191. In practice it may frequently be sufficient that the pressure is at least the pressure which can be calculated for a selected temperature, or the temperature is at most the temperature which can be calculated for a selected pressure from equation 1 wherein A equals 28554 and B equals 47.084.

In certain instances it may be most advantageous to control the pressure and temperature such that they belong to values of A and B which represent conditions of relatively low levels of preference as indicated hereinbefore. This may be the case, for example, when a certain combination of product quantity, composition and quality is desired. Thus, the above disclosure includes also all possible sub-ranges which may be defined by combining sets of A and B as disclosed. In particular, it may be advantageous during the production of the hydrocarbon fluid to keep a relevant property constant, which may be achieved by operating under a constant value of the parameters A and B. During the pyrolysis and during the production of the hydrocarbon fluid from the formation the pressure may be selected within wide ranges. Typically, a pressure of at least 1.5 bar is applied, more typically at least 1.6 bar, in particular at least 1.8 bar. Frequently, when the pyrolysis temperature is at least 300 C, a pressure of at least 1.6 bar may be applied, and below 300 C, a pressure of at least 1.8 bar may be applied. The upper limit of the pressure may be determined by the strength and the weight of the overburden. Frequently, under practical conditions, the pressure is less than 70 bar, more frequently less than 60 bar or even less than 50 bar.

The pressure may advantageously be controlled within a range of from 2 bar to 18 bar or 20 bar, or alternatively within a range of from 20 bar to 36 bar.

In a preferred embodiment, as indicated hereinbefore, a partial pressure of hydrogen is maintained. Typically the partial pressure is at least 0.2 bar, preferably at least 0.45 bar, and up to 35 bar, or even up to 50 bar, more typically in the range of from 0.6 bar to 20 bar, in particular in the range from 1 bar to 10 bar, more in particular in the range of from 5 bar to 7 bar.

Maintaining a hydrogen partial pressure within the formation in particular increases the API gravity of produced hydrocarbon fluids and reduces the production of long chain hydrocarbon fluids.

The present teachings as regards the partial pressure of hydrogen are applicable independent of the application of the temperature/pressure control of this invention.
At least 20%, typically at least 25%, preferably at least 35% of the initial total organic carbon content of the hydrocarbon containing formation, or the portion thereof subjected to pyrolysis may be transformed into hydrocarbon fluids. In practice frequently at most 90%
of the total organic carbon content of the hydrocarbon containing formation, or the portion thereof which is subjected to pyrolysis, may be transformed into hydrocarbon fluids, more frequently this may be at most 80%, or at most 70% or at most 60%.
In certain embodiments, after the pyrolysis, synthesis gas may be produced from hydrocarbons remaining within the hydrocarbon containing formation. The pyrolysis may produce a relatively high, substantially uniform permeability throughout the hydrocarbon containing formation or the pyrolysed portion thereof.

Such a relatively high, substantially uniform permeability allows the generation of synthesis gas without production of significant amounts of hydrocarbon fluids in the synthesis gas. The portion also has a large surface area and/or a large surface area/volume.
The large surface area may allow synthesis gas producing reactions to be substantially at equilibrium conditions during synthesis gas generation. The relatively high, substantially uniform permeability can result in a relatively high recovery efficiency of synthesis gas, as compared to synthesis gas generation in a hydrocarbon containing formation which has not been subjected to pyrolysis. This teaching is applicable independent of the application of the temperature/pressure control of this invention.

Pyrolysis of at least some hydrocarbon containing material may in some embodiments convert 20% of carbon initially available. Synthesis gas generation may convert at least an additional 10% and typically up to an additional 70% of the carbon initially available. In this manner, in situ production of synthesis gas from a hydrocarbon containing formation may allow conversion of larger amounts of carbon initially available within the portion.

Synthesis gas may be produced from the formation prior to or subsequent to producing the hydrocarbon fluid from the formation. The synthesis gas, although generally defined as a mixture of hydrogen (H2) and carbon monoxide (C0), may comprise additional components such as water, carbon dioxide (C02), methane and other gases.

The synthesis gas generation may be commenced before and/or after hydrocarbon fluid production decreases to an uneconomical level. In this manner, heat provided to pyrolyse may also be used to generate synthesis gas. For example, if a portion of the formation is 375 C after pyrolysation, then less additional heat is generally required to heat such portion to a temperature sufficient to support synthesis gas generation. In certain instances heat may be provided from one or more heat sources to heat the formation to a temperature sufficient to allow synthesis gas generation (for example in the range of from 400 C to 1200 C or higher). At the upper end of the temperature range, the generated synthesis gas may include mostly H2 and CO, in for example a 1:1 mole ratio. At the lower end of this temperature range, the generated synthesis gas may have a higher H2 to CO ratio.
Heating wells, heating sources and production wells within the formation for pyrolysing and producing hydrocarbon fluids from the formation may be utilized during synthesis gas production as an injection well to introduce synthesis gas producing fluid, as a production well, or as a heat source to heat the formation. Heat sources for the synthesis gas production may include any of the heat sources as disclosed hereinbefore.

Alternatively, heating may include transferring heat from a heat transfer fluid, for example steam or combustion products from a burner, flowing within a plurality of wellbores within the formation.

A synthesis gas generating fluid, for example liquid water, steam, carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof, may be provided to the formation.
For example, the synthesis gas generating fluid mixture may include steam and oxygen. The synthesis gas generating fluid may include aqueous fluid produced by pyrolysis of hydrocarbon containing material within another portion of the formation. Providing the synthesis gas generating fluid may alternatively include raising a water table of the formation to allow water to flow into it. Synthesis gas generating fluid may also be provided through an injection wellbore. The synthesis gas generating fluid will generally react with carbon in the formation to form H2, water (as liquid or as steam), C02, and/or CO.

Carbon dioxide may be separated from the synthesis gas and may be re-injected into the formation with the synthesis gas generating fluid. By a shift of the prevailing chemical equilibrium reactions, carbon dioxide added to the synthesis gas generating fluid may substantially inhibit further production of carbon dioxide during the synthesis gas generation. The carbon dioxide may also react with carbon in the formation to generate carbon monoxide.
Hydrocarbons such as ethane may be added to the synthesis gas generating fluid. When introduced into the formation, the hydrocarbons may crack to form hydrogen and/or methane. The presence of methane in the produced synthesis gas may increase its heating value.
Synthesis gas generating reactions are typically endothermic reactions. Heat may be added to the formation during synthesis gas production to keep the formation temperature at the desired level. Heat may be added from heat sources and/or from introducing synthesis gas generating fluid which has a higher temperature than the temperature of the formation. As an alternative, an oxidant may be added to the synthesis gas generating fluid, for example air, oxygen enriched air, oxygen, hydrogen peroxide, other oxidizing fluids, or combinations thereof. The oxidant may react with carbon within the formation to generate heat, and to result in production of C02 and/or CO. In a preierred embodiment oxygen and water (or steam) are provided to the formation, for example in a mole ratio of from 1:2 to 1:10, preferably from 1:3 to 1:7, for example 1:4.

The hydrocarbon containing formation may be maintained at a relatively high pressure during synthesis gas production. Synthesis gas may be generated in a wide pressure range, for example between 1 bar and 100 bar, more typically between 2 bar and 80 bar, especially between 5 bar and 60 bar. High operating pressures may result in an increased production of H2. High operating pressures may allow generation of electricity by passing produced synthesis gas through a turbine, and they may allow for smaller collection conduits to transport produced synthesis gas.
The synthesis gas may be generated in a wide temperature range, such as between 400 C and 1200 C, more typically between 600 C and 1000 C. At a relatively low synthesis gas generation temperature a synthesis gas may be produced which has a high H2 to CO
ratio. A relatively high formation temperature may produce a synthesis gas having a H2 to CO ratio that approaches 1, and the stream may include mostly (and in some cases substantially only) H2 and CO. At a formation temperature of about 700 C, the formation may produce a synthesis gas having a H2 to CO ratio of 2. Typically synthesis gas may be generated which has a H2 to CO mole ratio in the range of from 1:4 to 8:1, more typically in the range of from 1:2 to 4:1, in particular in the range of from 1:1 to 2.5:1. Certain embodiments may include blending a first synthesis gas with a second synthesis gas to produce synthesis gas of a desired composition.
The first and the second synthesis gases may be produced from different portions of the formation.

The hydrocarbon containing formation or the portion thereof which has been subjected to pyrolysation and optionally to synthesis gas generation may be allowed to cool or may be cooled to form a cooled, spent formation.
After production of hydrocarbon fluids and/or synthesis gas, a fluid (e.g., carbon dioxide) may be sequestered within the formation. To store a significant amount of fluid within the formation, the temperature of the formation will often need to be less than 100 C, for example down to 20 C. Water may be introduced into the formation to generate steam and reduce the temperature of the formation. The steam may be removed from the formation. The steam may be utilized for various purposes, for example for heating another portion of the formation, for generating synthesis gas in an adjacent portion of the formation, or as a steam flood in an oil reservoir. After the formation is cooled, fluid may be pressurized and sequestered in the formation.
Sequestering fluid within the formation may result in a significant reduction or elimination of fluid that is released to the environment due to operation of the present in situ process. The spent formation is especially useful for this purpose, because it has a structure of high porosity and high permeability for fluids, in particular gases.

The fluid to be sequestered may be injected under pressure, for example in the range of from 5 bar to 50 bar, into the cooled, spent formation and adsorbed onto hydrocarbon containing material in the formation.

Subsequent addition of water to the formation may inhibit desorption of the carbon dioxide. An example of a method for sequestering carbon dioxide is illustrated in US-A-5566756.

The synthesis gases described herein may be converted to hydrocarbons, which include methanol, or to other products, such as ammonia. For example, a Fischer-Tropsch hydrocarbon synthesis process may be configured to convert synthesis gas to paraffins. The synthesis gas may also be used in a catalytic methanation process to produce methane. Alternatively, the synthesis gas may be used for production of methanol, gasoline and diesel fuel, ammonia, and middle distillates.
The synthesis gas may also be used as a source of energy. For example, it may be used as a combustion fuel, to heat the hydrocarbon containing formation or to make steam and then run turbines for the generation of electricity. Synthesis gas may be used to generate electricity by reducing the pressure of the synthesis gas in turbines, or using the temperature of the synthesis gas to make steam and then run turbines. Synthesis gas may also be used in an energy generation unit such as a molten carbonate fuel cell, a solid oxide fuel cell, or other type of fuel cell.

The H2 to CO mole ratio for synthesis gas used as a feed gas for a Fischer-Tropsch reaction is typically about 2:1. The Fischer-Tropsch process typically produces branched and unbranched paraffins, which may be converted by hydrocracking to produce hydrocarbon products which include for example diesel, jet fuel and naphtha products. Examples of methods for conversion of synthesis gas to hydrocarbons in a Fischer-Tropsch process are illustrated in US-A-4096163, US-A-4594468, US-A-6085512 and US-A-6172124.

It may be desirable for the composition of produced synthesis gas, which may be used as a feed gas for a catalytic methanation process, to have a H2 to CO mole ratio of 3:1 to 4:1. Examples of a catalytic methanation process are illustrated in US-A-3992148, US-A-4130575 and US-A-4133825.

Examples of processes for production of methanol from synthesis gas are illustrated in US-A-4407973, US-A-4927857 and US-A-4994093.

Examples of process for producing engine fuels are illustrated in US-A-4076761, US-A-4138442 and US-A-4605680.

The following example illustrates the invention.
Example 1 Various samples of the Green River oil shale deposit in Colorado, USA, were pyrolysed at various temperatures and pressures to determine the effects of the pyrolysis temperature and pressure on the quality and the quantity of the produced hydrocarbon fluids.
A stainless steel pressure vessel was configured to hold an oil shale sample. The vessel and flow lines attached to the vessel were wrapped with electric heating tape to provide substantially uniform heating throughout the vessel and the flow lines. The flow lines comprised a backpressure valve for tests at elevated pressures.
After passing the valve, the products were cooled at atmospheric pressure in a conventional glass laboratory condenser and analysed. The test data was used to determine a pressure/temperature relationship for specific quality and yield aspects of the product by way of the equation 1 and the parameters A and B, as outlined hereinbefore. The results show that by increasing the pressure the content of hydrocarbons having a carbon number of 25 or more content is decreaL3ed, the API
gravity is increased, the ethylene/ethane ratio is decreased, the H/C ratio is increased and the yield of hydrocarbons relative to the Fischer Assay is decreased.
BRIEF DESCRIPTION OF THE DRAWINGS

Further advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description of the preferred embodiments and upon reference to the accompanying drawings in which:

FIG. 1 depicts an illustration of stages of heating a hydrocarbon containing formation;
FIG. 2 depicts a diagram of properties of a hydrocarbon containing formation;
FIG. 3 depicts an embodiment of a heat source pattern;

FIGS. 3a-3c depict embodiments of heat sources;
FIG. 4 depicts an embodiment of heater wells located in a hydrocarbon containing formation;
FIG. 5 depicts an embodiment of a pattern of heater wells in a hydrocarbon containing formation;
FIG. 6 depicts an embodiment of a heated portion of a hydrocarbon containing formation;

FIG. 7 depicts an embodiment of superposition of heat in a hydrocarbon containing formation;

FIG. 8 and FIG. 9 depict embodiments of a pattern of heat sources and production wells in a hydrocarbon containing formation;

FIG. 10 depicts an embodiment of a natural distributed combustor heat source;

FIG. 11 depicts a portion of an overburden of a formation with a heat source;

FIG. 12 and FIG. 13 depict embodiments of a natural distributed combustor heater;

FIG. 14 and FIG. 15 depict embodiments of a system for heating a formation;

FIGS. 16-21 depict several embodiments of an insulated conductor heat source;
FIG. 22 and FIGS. 23a-23b depict several embodiments of a centralizer;

FIG. 24 depicts an embodiment of a conductor-in-conduit heat source in a formation;
FIG. 25 depicts an embodiment of a heat source in a formation;

FIG. 26 depicts an embodiment of a surface combustor heat source;

FIG. 27 depicts an embodiment of a conduit for a heat source;

FIG. 28 depicts an embodiment of a flameless combustor heat source;

FIG. 29 depicts an embodiment of using pyrolysis water to generate synthesis gas in a formation;
FIG. 30 depicts an embodiment of synthesis gas production in a formation;
FIG. 31 depicts an embodiment of continuous synthesis gas production in a formation;

FIG. 32 depicts an embodiment of batch synthesis gas production in a formation;

FIG. 33 depicts an embodiment of producing energy with synthesis gas produced from a hydrocarbon containing formation;

FIG. 34 depicts an embodiment of producing energy with pyrolyzation fluid produced from a hydrocarbon containing formation;

FIG. 35 depicts an embodiment of synthesis gas production from a formation;

FIG. 36 depicts an embodiment of sequestration of carbon dioxide produced during pyrolysis in a hydrocarbon containing formation;

FIG. 37 depicts an embodiment of producing energy with synthesis gas produced from a hydrocarbon containing formation;

FIG. 38 depicts an embodiment of a Fischer-Tropsch process using synthesis gas produced from a hydrocarbon containing formation;

FIG. 39 depicts an embodiment of a Shell Middle Distillates process using synthesis gas produced from a hydrocarbon containing formation;

FIG. 40 depicts an embodiment of a catalytic methanation process using synthesis gas produced from a hydrocarbon containing formation;

FIG. 41 depicts an embodiment of production of ammonia and urea using synthesis gas produced from a hydrocarbon containing formation;
FIG. 42 depicts an embodiment of production of ammonia using synthesis gas produced from a hydrocarbon containing formation;
FIG. 43 depicts an embodiment of preparation of a feed stream for an ammonia process;

FIGS. 44-48 depict several embodiments for treating a relatively permeable formation;
FIG. 49 and FIG. 50 depict embodiments of heat sources in a relatively permeable formation;

FIGS. 51-57 depict several embodiments of heat sources in a relatively low permeability formation;
FIGS. 58-70 depict several embodiments of a heat source and production well pattern;

FIG. 71 depicts an embodiment of surface facilities for treating a formation fluid;

FIG. 72 depicts an embodiment of a catalytic flameless distributed combustor;
FIG. 73 depicts an embodiment of surface facilities for treating a formation fluid;

FIG. 74 depicts an embodiment of a square pattern of heat sources and production wells;

FIG. 75 depicts an embodiment of a heat source and production well pattern;

FIG. 76 depicts an embodiment of a triangular pattern of heat sources;

FIG. 76a depicts an embodiment of a square pattern of heat sources;

FIG. 77 depicts an embodiment of a hexagonal pattern of heat sources;

FIG. 77a depicts an embodiment of a 12 to 1 pattern of heat sources;

FIG. 78 depicts a temperature profile for a triangular pattern of heat sources;
FIG. 79 depicts a temperature profile for a square pattern of heat sources;
FIG. 79a depicts a temperature profile for a hexagonal pattern of heat sources;
FIG. 80 depicts a comparison plot between the average pattern temperature and temperatures at the coldest spots for various patterns of heat sources;

FIG. 81 depicts a comparison plot between the average pattern temperature and temperatures at various spots within triangular and hexagonal pattern of heat sources;
FIG. 81a depicts a comparison plot between the average pattern temperature and temperatures at various spots within a square pattern of heat sources;

FIG. 81b depicts a comparison plot between temperatures at the coldest spots of various pattern of heat sources;

FIG. 82 depicts extension of a reaction zone in a heated formation over time;

FIG. 83 and FIG. 84 depict the ratio of conductive heat transfer to radiative heat transfer in a formation;
FIGS. 85-88 depict temperatures of a conductor, a conduit, and an opening in a formation versus a temperature at the face of a formation;

FIG. 89 depicts a retort and collection system;

FIG. 90 depicts pressure versus temperature in an oil shale containing formation during pyrolysis;

FIG. 91 depicts quality of oil produced from an oil shale containing formation;

FIG. 92 depicts ethene to ethane ratio produced from an oil shale containing formation as a function of temperature and pressure;

FIG. 93 depicts yield of fluids produced from an oil shale containing formation as a function of temperature and pressure;

FIG. 94 depicts a plot of oil yield produced from treating an oil shale containing formation;
FIG. 95 depicts yield of oil produced from treating an oil shale containing formation;
FIG. 96 depicts hydrogen to carbon ratio of hydrocarbon condensate produced from an oil shale containing formation as a function of temperature and pressure;

FIG. 97 depicts olefin to paraffin ratio of hydrocarbon condensate produced from an oil shale containing formation as a function of pressure and temperature;

FIG. 98 depicts relationships between properties of a hydrocarbon fluid produced from an oil shale containing formation;

FIG. 99 depicts quantity of oil produced from an oil shale containing formation as a function of partial pressure of H2;

FIG. 100 depicts ethene to ethane ratios of fluid produced from an oil shale containing formation as a function of temperature and pressure;

FIG. 101 depicts hydrogen to carbon atomic ratios of fluid produced from an oil shale containing formation as a function of temperature and pressure;
FIG. 102 depicts an embodiment of an apparatus for a drum experiment;

FIG. 103 depicts a plot of ethene to ethane ratio versus hydrogen concentration;

FIG. 104 depicts a heat source and production well pattern for a field experiment in an oil shale containing formation;

FIG. 105 depicts a cross-sectional view of the field experiment;

FIG. 106 depicts a plot of temperature within the oil shale containing formation during the field experiment;
FIG. 107 depicts pressure within the oil shale containing formation during the field experiment;

FIG. 108 depicts a plot of API gravity of a fluid produced from the oil shale containing formation during the field experiment versus time;

FIG. 109 depicts average carbon numbers of fluid produced from the oil shale containing formation during the field experiment versus time;
FIG. 110 depicts density of fluid produced from the oil shale containing formation during the field experiment versus time;

FIG. 111 depicts a plot of weight percent of hydrocarbons within fluid produced from the oil shale containing formation during the field experiment;

FIG. 112 depicts a plot of an average yield of oil from the oil shale containing formation during the field experiment;

FIG. 113 depicts experimental data from laboratory experiments on oil shale;

FIG. 114 depicts total hydrocarbon production and liquid phase fraction versus time of a fluid produced from an oil shale containing formation;

FIG. 115 depicts weight percent of paraffins versus vitrinite reflectance;

FIG. 116 depicts weight percent of cycloalkanes in produced oil versus vitrinite reflectance;
FIG. 117 depicts weight percentages of paraffins and cycloalkanes in produced oil versus vitrinite reflectance;

FIG. 118 depicts phenol weight percent in produced oil versus vitrinite reflectance;
FIG. 119 depicts aromatic weight percent in produced oil versus vitrinite reflectance;

FIG. 120 depicts ratio of paraffins and aliphatics to aromatics versus vitrinite reflectance;

FIG. 121 depicts yields of paraffins versus vitrinite reflectance;

FIG. 122 depicts yields of cycloalkanes versus vitrinite reflectance;

FIG. 123 depicts yields of cycloalkanes and paraffins versus vitrinite reflectance;

FIG. 124 depicts yields of phenol versus vitrinite reflectance;

FIG. 125 depicts API gravity as a function of vitrinite reflectance;

FIG. 126 depicts yield of oil from a coal containing formation as a function of vitrinite reflectance;
FIG. 127 depicts C02 yield from coal having various vitrinite reflectances;

FIG. 128 depicts C02 yield versus atomic 0/C ratio for a coal containing formation;

FIG. 129 depicts a schematic of a coal cube experiment;

FIG. 130 depicts in situ temperature profiles for electrical resistance heaters, and natural distributed combustion heaters;

FIG. 131 depicts equilibrium gas phase compositions produced from experiments on a coal cube;

FIG. 132 depicts cumulative production of gas as a function of temperature produced by heating a coal cube;
FIG. 133 depicts cumulative condensable hydrocarbons and water as a function of temperature produced by heating a coal cube;
FIG. 134 depicts the compositions of condensable hydrocarbons produced when various ranks of coal were treated;

FIG. 135 depicts thermal conductivity of coal versus temperature;

FIG. 136 depicts a cross-sectional view of an in situ experimental field test;

FIG. 137 depicts locations of heat sources and wells in an experimental field test;

FIG. 138 and FIG. 139 depict temperature versus time in an experimental field test;

FIG. 140 depicts volume of oil produced from an experimental field test as a function of time;
FIG. 141 depicts carbon number distribution of fluids produced from an experimental field test;

FIG. 142 depicts weight percent of a hydrocarbon produced from two laboratory experiments on coal from the 1 field test site versus carbon number distribution;

FIG. 143 depicts fractions from separation of coal oils treated by Fischer assay and treated by slow heating in a coal cube experiment;

FIG. 144 depicts percentage ethene to ethane produced from a coal containing formation as a function of heating rate in an experimental field test;

FIG. 145 depicts product quality of fluids produced from a coal containing formation as a function of heating rate in an experimental field test;
FIG. 146 depicts weight percentages of various fluids produced from a coal containing formation for various heating rates in an experimental field test;

FIG. 147 depicts C02 produced at three different locations versus time in an experimental field test;
FIG. 148 depicts volatiles produced from a coal containing formation in an experimental field test versus cumulative energy content;

FIG. 149 depicts volume of gas produced from a coal containing formation in an experimental field test as a function of time;

FIG. 150 depicts volume of oil produced from a coal containing formation in an experimental field test as a function of energy input;

FIG. 151 depicts synthesis gas production from the coal containing formation in an experimental field test versus the total water inflow;

FIG. 152 depicts additional synthesis gas production from the coal containing formation in an experimental field test due to injected steam;

FIG. 153 depicts the effect of methane injection into a heated formation;

FIG. 154 depicts the effect of ethane injection into a heated formation;

FIG. 155 depicts the effect of propane injection into a heated formation;

FIG. 156 depicts the effect of butane injection into a heated formation;

FIG. 157 depicts composition of gas produced from a formation versus time;
FIG. 158 depicts synthesis gas conversion versus time;

FIG. 159 depicts calculated equilibrium gas dry mole fractions for a reaction of coal with water;

FIG. 160 depicts calculated equilibrium gas wet mole fractions for a reaction of coal with water;

FIG. 161 depicts an example of pyrolysis and synthesis gas production stages in a coal containing formation;

FIG. 162 depicts an example of low temperature in situ synthesis gas production;

FIG. 163 depicts an example of high temperature in situ synthesis gas production;

FIG. 164 depicts an example of in situ synthesis gas production in a hydrocarbon containing formation;

FIG. 165 depicts a plot of cumulative adsorbed methane and carbon dioxide versus pressure in a coal containing formation;

FIG. 166 depicts an embodiment of in situ synthesis gas production integrated with a Fischer-Tropsch process;
FIG. 167 depicts a comparison between numerical simulation data and experimental field test data of synthesis gas composition produced as a function of time;
FIG. 168 depicts weight percentages of carbon compounds versus carbon number produced from a heavy hydrocarbon containing formation;

FIG. 169 depicts weight percentages of carbon compounds produced from a heavy hydrocarbon containing formation versus heating rate and pressure;
FIG. 170 depicts a plot of oil production versus time in a heavy hydrocarbon containing formation;

FIG. 171 depicts ratio of heat content of fluids produced from a heavy hydrocarbon containing formation to heat input versus time;

FIG. 172 depicts numerical simulation data of weight percentage versus carbon number distribution produced from a heavy hydrocarbon containing formation;

FIG. 173 depicts H2 mole percent in gases produced from heavy hydrocarbon drum experiments;

FIG. 174 depicts API gravity of liquids produced from heavy hydrocarbon drum experiments;
FIG. 175 depicts a plot of hydrocarbon liquids production over time for an in situ field experiment;
FIG. 176 depicts a plot of hydrocarbon liquids, gas, and water for an in situ field experiment;

FIG. 177 depicts pressure at wellheads as a function of time from a numerical simulation;

FIG. 178 depicts production rate of carbon dioxide and methane as a function of time from a numerical simulation;

FIG. 179 depicts cumulative methane produced and net carbon dioxide injected as a function of time from a numerical simulation;

FIG. 180 depicts pressure at wellheads as a function of time from a numerical simulation;
FIG. 181 depicts production rate of carbon dioxide as a function of time from a numerical simulation; and FIG. 182 depicts cumulative net carbon dioxide injected as a function of time from a numerical simulation.

While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and may herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION OF THE INVENTION
The following description generally relates to systems and methods for treating a hydrocarbon containing formation (e.g., a formation containing coal (including lignite, sapropelic coal, etc.), oil shale, carbonaceous shale, shungites, kerogen, oil, kerogen and oil in a low permeability matrix, heavy hydrocarbons', asphaltites, natural mineral waxes, formations wherein kerogen is blocking production of other hydrocarbons, etc.). Such formations may be treated to yield relatively high quality hydrocarbon products, hydrogen, and other products.

As used herein, "a method of treating a hydrocarbon containing formation" may be used interchangeably with "an in situ conversion prbcess for hydrocarbons."
"Hydrocarbons" are generally defined as organic material that contains carbon and hydrogen in their molecular structures. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulphur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, and oils. Hydrocarbons may be located within or adjacent to mineral matrices within the earth.
Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media.

"Kerogen" is generally defined as a solid, insoluble hydrocarbon that has been converted by natural degradation (e.g., by diagenesis) and that principally contains carbon, hydrogen, nitrogen, oxygen, and sulphur.
Coal and oil shale are typical examples of materials that contain kerogens. "Bitumen" is generally defined as a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulphide.
"Oil" is generally defined as a fluid containing a complex mixture of condensable hydrocarbons.
The terms "formation fluids" and "produced fluids"
generally refer to fluids removed from a hydrocarbon containing formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, and water (steam).

The term ""mobilized fluid" generally refers to fluids within the formation that are able to flow because of thermal treatment of the formation. Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. As used herein, "hydrocarbon fluids" generally refer to compounds including primarily hydrogen and carbon. Hydrocarbon fluids may include other elements in addition to hydrogen and carbon such as, but not limited to, nitrogen, oxygen, and sulphur. Non-hydrocarbon fluids may include, but are not limited to, hydrogen ("H2"), nitrogen ("N2"), carbon monoxide, carbon dioxide, hydrogen sulphide, water, and ammonia.

A"carbon number" generally refers to a number of carbon atoms within a molecule. As described herein, carbon number distributions are determined by true boiling point distribution and gas liquid chromatography.
A "heat source" is generally defined as any system configured to provide heat to at least a portion of a formation. For example, a heat source may include electrical heaters such as an insulated conductor, an elongated member, and a conductor disposed within a conduit, as described in embodiments herein. A heat source may also include heat sources that generate heat by burning a fuel external to or within a formation such as surface burners, flameless distributed combustors, and natural distributed combustors, as described in embodiments herein. In addition, it is envisioned that in some embodiments heat provided to or generated in one or more heat sources may by supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer media that directly or indirectly heats the formation.
It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. Thus, for example, for a given -formation some heat sources may supply heat from electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources \e.g., chemical reactions, solar energy, wind energy, or other sources of renewable energy). A chemical reaction may include an exothermic reaction such as, but not limited to, an oxidation reaction that may take place in at least a portion of a formation. A heat source may also include a heater that may be configured to provide heat to a zone proximate to and/or surrounding a heating location such as a heater well. Heaters may be, but are not limited to, electric heaters, burners, and natural distributed combustors.

A"heater" is generally defined as any system configured to generate heat in a well or a near wellbore region. A "unit of heat sources" refers to a minimal number of heat sources that form a template that is repeated to create a pattern of heat sources within a formation. For example, a heater may generate heat by burning a fuel external to or within a formation such as surface burners, flameless distributed combustors, and natural distributed combustors, as described in embodiments herein.
The term "welibore" generally refers to a hole in a formation made by drilling. A wellbore may have a substantially circular cross-section, or a cross-section in other shapes as well (e.g., circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes). As used herein, the terms "well" and "opening," when referring to an opening in the formation, may also be used interchangeably with the term "wellbore."

As used herein, the phrase "natural distributed combustor" generally refers to a heater that uses an oxidant to oxidize at least a portion of the carbon in the formation to generate heat, and wherein the oxidation takes place in a vicinity proximate to a wellbore. Most of the combustion products produced in the natural distributed combustor are removed through the wellbore.
The term "orifices," as used herein, generally describes openings having a wide variety of sizes and cross-sectional shapes including, but not limited to, circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes.

As used herein, a "reaction zone" generally refers to a volume of a hydrocarbon containing formation that is subjected to a chemical reaction such as an oxidation reaction.

As used herein, the term "insulated conductor"
generally refers to any elongated material that may conduct electricity and that is covered, in whole or in part, by an electrically insulating material. The term "self-controls" generally refers to controlling an output of a heater without external control of any type.
"Pyrolysis" is generally defined as the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. In the context of this patent, heat for pyrolysis may originate in an oxidation reaction and then such heat may be transferred to a section of the formation to cause pyrolysis.

As used herein, a "pyrolyzation fluid" or "pyrolysis products" generally refers to a fluid produced substantially during pyrolysis of hydrocarbons. As used herein, a "pyrolysis zone" generally refers to a volume of hydrocarbon containing formation that is reacted or reacting to form a pyrolyzation fluid.
"Cracking" generally refers to a process involving decomposition and molecular recombination of organic compounds wherein a number of molecules becomes larger.
In cracking, a series of reactions take place accompanied by a transfer of hydrogen atoms between molecules.
Cracking fundamentally changes the chemical structure of the molecules. For example, naphtha may undergo a thermal cracking reaction to form ethene and H2.

The term "superposition of heat" is generally defined as providing heat from at least two heat sources to a selected section of the portion of the formation such that the temperature of the formation at least at one location between the two wells is influenced by at least two heat sources.
The term "fingering" generally refers to injected fluids bypassing portions of a formation because of variations in transport characteristics (e.g., permeability).
"Thermal conductivity" is generally defined as the property of a material that describes the rate at which heat flows, in steady state, between two surfaces of the material for a given temperature difference between the two surfaces.
"Fluid pressure" is generally defined as a pressure generated by a fluid within a formation. "Lithostatic pressure" is sometimes referred to as lithostatic stress and is generally defined as a pressure within a formation equal to a weight per unit area of an overlying rock mass. "Hydrostatic pressure" is generally defined as a pressure within a formation exerted by a column of water.
"Condensable hydrocarbons" means the hydrocarbons that condense at 25 C at one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4.
"Non-condensable hydrocarbons" means the hydrocarbons that do not condense at 25 C and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.
"Olefins" are generally defined as unsaturated hydrocarbons having one or more non-aromatic carbon-to-carbon double bonds.

"Urea" is generally described by a molecular formula of NH2-CO-NH2. Urea can be used as a fertilizer.
"Synthesis gas" is generally defined as a mixture including hydrogen and carbon monoxide used for synthesizing a wide range of compounds. Additional components of synthesis gas may include water, carbon dioxide, nitrogen, methane and other gases. Synthesis gas may be generated by a variety of processes and feedstocks.

"Reforming" is generally defined as decomposition or cracking of hydrocarbon gases or low-octane petroleum fractions by heat and pressure. Reforming may be done without a catalyst (thermoforming) or with a catalyst (e.g., molybdenum, platinum). Steam reforming of natural gas produces H2 and carbon monoxide from methane and water.

"Sequestration" generally refers to storing a gas that is a by-product of a process rather than venting the gas to the atmosphere.

The term "dipping" is generally defined as sloping downward or inclining from a plane parallel to the earth's surface, assuming the plane is flat (i.e., a "horizontal" plane). A"dip" is generally defined as an angle that a stratum or similar feature may make with a horizontal plane. A "steeply dipping" hydrocarbon containing formation generally refers to a hydrocarbon containing formation lying at an angle of at least 20 from a horizontal plane. As used herein, "down dip"
generally refers to downward along a direction parallel to a dip in a formation. As used herein, "up dip"

generally refers to upward along a direction parallel to a dip of a formation. "Strike" refers to the course or bearing of hydrocarbon material that is normal to the direction of the dip.
. The term "subsidence" is generally defined as downward movement of a portion of a formation relative to an initial elevation of the surface.
"Thickness" of a layer refers to the thickness of a cross-section of a layer, wherein the cross-section is normal to a face of the layer.
"Coring" is generally defined as a process that generally includes drilling a hole into a formation and removing a substantially solid mass of the formation from the hole.
A "surface unit" is generally defined as an ex situ treatment unit.

"Middle distillates" generally refers to hydrocarbon mixtures with a boiling point range that may correspond substantially with that of kerosene and gas oil fractions obtained in a conventional atmospheric distillation of crude oil material. The middle distillate boiling point range may include temperatures between about 150 C and about 360 C, with a fraction boiling point between about 200 C and about 360 C. Middle distillates may be referred to as gas oil.

A "boiling point cut" is generally defined as a hydrocarbon liquid fraction that may be separated from hydrocarbon liquids when the hydrocarbon liquids are heated to a boiling point range of the fraction.
The term "selected mobilized section" refers to a section of a relatively permeable formation that is at an average temperature within a mobilization temperature range. The term "selected pyrolyzation section" refers to a section of a relatively permeable formation that is at an average temperature within a pyrolyzation temperature range.
"Enriched air" generally refers to air having a larger mole fraction of oxygen than air in the atmosphere. Enrichment of air is typically done to increase its combustion-supporting ability.
"Heavy hydrocarbons" are generally defined as viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulphur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts.
Heavy hydrocarbons may be classified by API gravity.
Heavy hydrocarbons generally have an API gravity below about 20 . Heavy oil, for example, generally has an API
gravity of about 10-20 whereas tar generally has an API
gravity below about 10 . The viscosity of heavy hydrocarbons is generally greater than about 300 centipoise at 15 C. Tar generally has a viscosity greater than about 10,000 centipoise at 15 C. Heavy hydrocarbons may also include aromatics, or other complex ring hydrocarbons.

Heavy hydrocarbons may be found in a relatively permeable formation. The relatively permeable formation may include heavy hydrocarbons entrained in, for example, sand or carbonate. "Relatively permeable" is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (e.g., 10 or 100 millidarcy). "Relatively low permeability" is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy. One Darcy is equal to about 0.99 square micrometers. An impermeable layer generally has a permeability of less than about 0.1 millidarcy.

The term "upgrade" refers to increasing the API
gravity of heavy hydrocarbons.

The phrase "off peak" times generally refers to times of operation where utility energy is less commonly used and, therefore, less expensive.
The term "low viscosity zone" generally refers to a section of a formation where at least a portion of the fluids are mobilized.

Tar contained in sand in a formation is generally referred to as a "tar sand formation."

"Thermal fracture" refers to fractures created in a formation caused by expansion or contraction of a formation and/or fluids within the formation, which is in turn caused by increasing/decreasing the temperature of the formation and/or fluids within the formation, and/or by increasing/decreasing a pressure of fluids within the formation due to heating.

"Vertical hydraulic fracture" refers to a fracture at least partially propagated along a vertical plane in a formation, wherein the fracture is created through injection of fluids into a formation.

Hydrocarbons in formations may be treated in various ways to produce many different products. In certain embodiments such formations may be treated in stages.
FIG. 1 illustrates several stages of heating a hydrocarbon containing formation. FIG. 1 also depicts an example of yield (barrels of oil equivalent per ton) (y axis) of formation fluids from a hydrocarbon containing formation versus temperature ( C) (x axis) of the formation.

Desorption of methane and vaporization of water occurs during stage 1 heating in FIG. 1. For example, when a hydrocarbon containing formation is initially heated, hydrocarbons in the formation may desorb adsorbed methane. The desorbed methane may be produced from the formation. If the hydrocarbon containing formation is heated further, water within the hydrocarbon containing formation may be vaporized. In addition, the vaporized water may be produced from the formation. Heating of the formation through stage 1 is in many instances preferably performed as quickly as possible.
After stage 1 heating, the formation may be heated further such that a temperature within the formation reaches (at least) an initial pyrolyzation temperature (e.g., the temperature at the lower end of the temperature range shown as stage 2). A pyrolysis temperature range may vary depending on types of hydrocarbons within the formation. For example, a pyrolysis temperature range may include temperatures between about 250 C and about 900 C. In an alternative embodiment, a pyrolysis temperature range may include temperatures between about 270 C to about 400 C.

Hydrocarbons within the formation may be pyrolyzed throughout stage 2.

Formation fluids including pyrolyzation fluids may be produced from the formation. The pyrolyzation fluids may include, but are not limited to, hydrocarbons, hydrogen, carbon dioxide, carbon monoxide, hydrogen sulphide, ammonia, nitrogen, water and mixtures thereof. As the temperature of the formation increases, the condensable hydrocarbons of produced formation fluid tends to decrease, and the formation will in many instances tend to produce mostly methane and hydrogen. If a hydrocarbon containing formation is heated throughout an entire pyrolysis range, the formation may produce only small amounts of hydrogen towards an upper limit of the pyrolysis range. After all of the available hydrogen is depleted, a minimal amount of fluid production from the formation will typically occur.
After pyrolysis of hydrocarbons, a large amount of carbon and some hydrogen may still be present in the formation. A significant portion of remaining carbon in the formation can be produced from the formation in the form of synthesis gas. Synthesis gas generation may take place during stage 3 heating as shown in FIG. 1. Stage 3 may include heating a hydrocarbon containing formation to a temperature sufficient to allow synthesis gas generation. For example, synthesis gas may be produced within a temperature range from about 400 C to about 1200 C. The temperature of the formation when the synthesis gas generating fluid is introduced to the formation will in many instances determine the composition of synthesis gas produced within the formation. If a synthesis gas generating fluid is introduced into a formation at a temperature sufficient to allow synthesis gas generation, then synthesis gas may be generated within the formation. Th(--; generated synthesis gas may be removed from the formation. A large volume of synthesis gas may be produced during generation of synthesis gas generation.

Depending on the amounts of fluid produced, total energy content of fluids produced from a hydrocarbon containing formation may in some instances stay relatively constant throughout pyrolysis and synthesis gas generation. For example, during pyrolysis, at relatively low formation temperatures, a significant portion of the produced fluid may be condensable hydrocarbons that have a high energy content. At higher pyrolysis temperatures, however, less of the formation fluid may include condensable hydrocarbons, and more non-condensable formation fluids may be produced. In this manner, energy content per unit volume of the produced fluid may decline slightly during generation of predominantly non-condensable formation fluids. During synthesis gas generation, energy content per unit volume of produced synthesis gas declines significantly compared to energy content of pyrolyzation fluid. The volume of the produced synthesis gas, however, will in many instance increase substantially, thereby compensating for the decreased energy content.

As explained below, the van Krevelen diagram shown in FIG. 2 depicts a plot of atomic hydrogen to carbon ratio (y axis) versus atomic oxygen to carbon ratio (x axis) for various types of kerogen. This diagram shows the maturation sequence for various types of kerogen that typically occurs over geologic time due to temperature, pressure, and biochemical degradation. The maturation may be accelerated by heating in situ at a controlled rate and/or a controlled pressure.

A van Krevelen diagram may be useful for selecting a resource for practicing various embodiments described herein (see discussion below). Treating a formation containing kerogen in region 5 will in many instances produce, e.g., carbon dioxide, non-condensable hydrocarbons, hydrogen, and water, along with a relatively small amount of condensable hydrocarbons.
Treating a formation containing kerogen in region 7 will in many instances produce, e.g., carbon condensable and non-condensable hydrocarbons, carbon dioxide, hydrogen, and water. Treating a formation containing kerogen in region 9 will in many instances produce, e.g., methane and hydrogen. A formation containing kerogen in region 7, for example, may in many instances be selected for treatment because doing so will tend to produce larger quantities of valuable hydrocarbons, and lower quantities of undesirable products such as carbon dioxide and water, since the region 7 kerogen has already undergone dehydration and/or decarboxylation over geological time. In addition, region 7 kerogen can also be further treated to make other useful products (e.g., methane, hydrogen, and/or synthesis gas) as such kerogen transforms to region 9 kerogen.
If a formation containing kerogen in region 5 or 7 was selected for treatment, then treatment pursuant to certain embodiments described herein would cause such kerogen to transform during treatment (see arrows in FIG. 2) to a region having a higher number (e.g., region 5 kerogen could transform to region 7 kerogen and possibly then to region 9 kerogen, or region 7 kerogen could transform to region 9 kerogen). Thus, certain embodiments described herein cause expedited maturation of kerogen, thereby allowing production of valuable products.

If region 5 kerogen, for example, is treated, then substantial carbon dioxide may be produced due to decarboxylation of hydrocarbons in the formation. In addition, treating region 5 kerogen may also produce some hydrocarbons (e.g., primarily methane). Treating region 5 kerogen may also produce substantial amounts of water due to dehydration of kerogen in the formation.

Production of such compounds from a formation may leave residual hydrocarbon&relatively enriched in carbon.
Oxygen content of the hydrocarbons will in many instances decrease faster than a hydrogen content of the hydrocarbons during production of such compounds.
Therefore, as shown in FIG. 2, production of such compounds may result in a larger decrease in the atomic oxygen to carbon ratio than a decrease in the atomic hydrogen to carbon ratio (see region 5 arrows in FIG. 2 which depict more horizontal than vertical movement).
If region 7 kerogen is treated, then typically at least some of the hydrocarbons in the formation are pyrolyzed to produce condensable and non-condensable hydrocarbons. For example, treating region 7 kerogen may result in production of oil from hydrocarbons, as well as some carbon dioxide and water (albeit generally less carbon dioxide and water than is produced when the region 5 kerogen is treated). Therefore, the atomic hydrogen to carbon ratio of the kerogen will in many instances decrease rapidly as the kerogen in region 7 is treated. The atomic oxygen to carbon ratio of the region 7 kerogen, however, will in many instances decrease much slower than the atomic hydrogen to carbon ratio of the region 7 kerogen.
Kerogen in region 9 may be treated to generate methane and hydrogen. For example, if such kerogen was previously treated (e.g., it was previously region 7 kerogen), then after pyrolysis longer hydrocarbon chains of the hydrocarbons may have already cracked and produced from the formation. Carbon and hydrogen, however, may still be present in the formation.

If kerogen in region 9 were heated to a synthesis gas generating temperature and a synthesis gas generating fluid (e.g., steam) were added to the region 9 kerogen, then at least a portion of remaining hydrocarbons in the formation may be produced from the formation in the form of synthesis gas. For region 9 kerogen, the atomic hydrogen to carbon ratio and the atomic oxygen to carbon ratio in the hydrocarbons may significantly decrease as the temperature rises. In this manner, hydrocarbons in the formation may be transformed into relatively pure carbon in region 9. Heating region 9 kerogen to still higher temperatures will tend to transform such kerogen into graphite 11.

A hydrocarbon containing formation may have a number of properties that will depend on, for example, a composition of at least some of the hydrocarbons within the formation. Such properties tend to affect the composition and amount of products that are produced from a hydrocarbon containing formation. Therefore, properties of a hydrocarbon containing formation can be used to determine if and/or how a hydrocarbon containing formation could optimally be treated.

Kerogen is composed of organic matter that has been transformed due to a maturation process. Hydrocarbon containing formations that include kerogen include, but are not limited to, coal containing formations and oil shale containing formations. Examples of hydrocarbon containing formations that may not include kerogen are formations containing heavy hydrocarbons (e.g., tar sands). The maturation process may include two stages: a biochemical stage and a geochemical stage. The biochemical stage typically involves degradation of organic material by both aerobic and anaerobic organisms.
The geochemical stage typically involves conversion of organic matter due to temperature changes and significant pressures. During maturation, oil and gas may be produced as the organic matter of the kerogen is transformed.

The van Krevelen diagram shown in FIG. 2 classifies various natural deposits of kerogen. For example, kerogen may be classified into four distinct groups:
type I, type II, type III, and type IV, which are illustrated by the four branches of the van Krevelen diagram. This drawing shows the maturation sequence for kerogen, which typically occurs over geological time due to temperature and pressure. The types depend upon precursor materials of the kerogen. The precursor materials transform over time into macerals, which are microscopic structures that have different structures and properties based on the precursor materials from which they are derived. Oil shale may be described as a kerogen type I or type II and may primarily contain macerals from the liptinite group. Liptinites are derived from plants, specifically the lipid rich and resinous parts. The concentration of hydrogen within liptinite may be as high as 9 weight o. In addition, liptinite has a relatively high hydrogen to carbon ratio and a relatively low atomic oxygen to carbon ratio. A
type I kerogen may also be further classified as an alginite, since type I kerogen may include primarily algal bodies. Type I kerogen may resu:Lt from deposits made in lacustrine environments. Type II kerogen may develop from organic matter that was deposited in marine environments.

Type III kerogen may generally include vitrinite macerals. Vitrinite is derived from cell walls and/or woody tissues (e.g., stems, branches, leaves and roots of plants). Type III kerogen may be present in most humic coals. Type III kerogen may develop from organic matter that was deposited in swamps. Type IV kerogen includes the inertinite maceral group. This group is composed of plant material such as leaves, bark and stems that have undergone oxidation during the early peat stages of burial diagenesis. It is chemically similar to vitrinite but has a high carbon and low hydrogen content. Thus, it is considered inert.
The dashed lines in FIG. 2 correspond to vitrinite reflectance. The vitrinite reflectance is a measure of maturation. As kerogen undergoes maturation, the composition of the kerogen usually changes. For example, as kerogen undergoes maturation, volatile matter of kerogen tends to decrease. Rank classifications of kerogen indicate the level to which kerogen has matured.
For example, as kerogen undergoes maturation, the rank of kerogen increases. Therefore, as rank increases, the volatile matter of kerogen tends to decrease. In addition, the moisture content of kerogen generally decreases as the rank increases. At higher ranks, however, the moisture content may become relatively constant. For example, higher rank kerogens that have undergone significant maturation, such as semi-anthracite or anthracite coal, tend to have a higher carbon content and a lower volatile matter content than lower rank kerogens such as lignite. For example, rank stages of coal containing formations include the following classifications, which are listed in order of increasing rank and maturity for type III kerogen: wood, peat, lignite, sub-bituminous coal, high volatile bituminous coal, medium volatile bituminous coal, low volatile bituminous coal, semi-anthracite, and anthracite. In addition, as rank increases, kerogen tends to exhibit an increase in aromatic nature.

Hydrocarbon containing formations may be selected for in situ treatment based on properties of at least a portion of the formation. For example, a formation may be selected based on richness, thickness, and depth (i.e., thickness of overburden) of the formation. In addition, a formation may be selected that will have relatively high quality fluids produced from the formation. In certain embodiments the quality of the fluids to be produced may be assessed in advance of treatment, thereby generating significant cost savings since only more optimal formations will be selected for treatment. Properties that may be used to assess hydrocarbons in a formation include, but are not limited to, an amount of hydrocarbon liquids that tend to be produced from the hydrocarbons, a likely API gravity of the produced hydrocarbon liquids, an amount of hydrocarbon gas that tend to be produced from the hydrocarbons, and/or an amount of carbon dioxide and water that tend to be produced from the hydrocarbons.

Another property that may be used to assess the quality of fluids produced from certain kerogen containing formations is vitrinite reflectance. Such formations include, but are not limited to, coal containing formations and oil shale containing formations. Hydrocarbon containing foimations that include kerogen can typically be assessed/selected for treatment based on a vitrinite reflectance of the kerogen. Vitrinite reflectance is often related to a hydrogen to carbon atomic ratio of a kerogen and an oxygen to carbon atomic ratio of the kerogen, as shown by the dashed lines in Fig. 2. For example, a van Krevelen diagram may be useful in selecting a resource for an in situ conversion process.

Vitrinite reflectance of a kerogen in a hydrocarbon containing formation tends to indicate which fluids may be produced from a formation upon heating. For example, a vitrinite reflectance of approximately 0.5% to approximately 1.5% tends to indicate a kerogen that, upon heating, will produce fluids as described in region 7 above. Therefore, if a hydrocarbon containing formation having such kerogen is heated, a significant amount (e.g., majority) of the fluid produced by such heating will often include oil and other such hydrocarbon fluids.
In addition, a vitrinite reflectance of approximately 1.5% to 3.0% may indicate a kerogen in region 9 as described above. If a hydrocarbon containing formation having such kerogen is heated, a significant amount (e.g., majority) of the fluid produced by such heating may include methane and hydrogen (and synthesis gas, if, for example, the temperature is sufficiently high and steam is injected). In an embodiment, at least a portion of a hydrocarbon containing formation selected for treatment in situ has a vitrinite reflectance in a range between about 0.2% and about 3.0%. Alternatively, at least a portion of a hydrocarbon containing formation selected for treatment has a vitrinite reflectance from about 0.5% to about 2.0%, and, in some circumstances, the vitrinite reflectance may range from about 0.5% to 1.0%.
Such ranges of vitrinite reflectance tend to indicate that relatively higher quality formation fluids will be produced from the formation.

In an embodiment, a hydrocarbon containing formation may be selected for treatment based on a hydrogen content within the hydrocarbons in the formation. For example, a method of treating a hydrocarbon containing formation may include selecting a portion of the hydrocarbon containing formation for treatment having hydrocarbons with a hydrogen content greater than about 3 weight %, 3.5 weight %, or 4 weight % when measured on a dry, ash-free basis. In addition, a selected section of a hydrocarbon containing formation may include hydrocarbons with an atomic hydrogen to carbon ratio that falls within a range from about 0.5 to about 2, and in many instances from about 0.70 to about 1.65.
Hydrogen content of a hydrocarbon containing formation may significantly affect a composition of hydrocarbon fluids produced from a formation. For example, pyrolysis of at least some of the hydrocarbons within the heated portion may generate hydrocarbon fluids that may include a double bond or a radical. Hydrogen within the formation may reduce the double bond to a single bond. In this manner, reaction of generated hydrocarbon fluids with each other and/or with additional components in the formation may be substantially inhibited. For example, reduction of a double bond of the generated hydrocarbon fluids to a single bond may reduce polymerization of the generated hydrocarbons.
Such polymerization tends to reduce the amount of fluids produced.

In addition, hydrogen within the formation may also neutralize radicals in the generated hydrocarbon fluids.
In this manner, hydrogen present in the formation may substantially inhibit reaction of hydrocarbon fragments by transforming the hydrocarbon fragments into relatively short chain hydrocarbon fluids. The hydrocarbon fluids may enter a vapour phase and may be produced from the formation. The increase in the hydrocarbon fluids in the vapour phase may significantly reduce a potential for producing less desirable products within the selected section of the formation.

It is believed that if too little hydrogen is present in the formation, then the amount and quality of the produced fluids will be negatively affected. If too little hydrogen is naturally present, then in some embodiments hydrogen or other reducing fluids may be added to the formation.

When heating a portion of a hydrocarbon containing formation, oxygen within the portion may form carbon dioxide. It may be desirable to reduce the production of carbon dioxide and other oxides. In an embodiment, production of carbon dioxide may be reduced by selecting and treating a portion of a hydrocarbon containing formation having a vitrinite reflectance of greater than about 0.5%. In addition, an amount of carbon dioxide produced from a formation may vary depending on, for example, an oxygen content of a treated portion of the hydrocarbon containing formation. Certain embodiments may thus include selecting and treating a portion of the formation having a kerogen with an atomic oxygen weight percentage of less than about 20%, 15%, and/or 10%. In addition, certain embodiments may include selecting and processing a formation containing kerogen with an atomic oxygen to carbon ratio of less than about 0.15.
Alternatively, at least some of the hyurocarbons in a portion of a formation selected for treatment may have an atomic oxygen to carbon ratio of about 0.03 to about 0.12. In this manner, production of carbon dioxide and other oxides from an in situ conversion process for hydrocarbons may be reduced.
Heating a hydrocarbon containing formation may include providing a large amount of energy to heat sources located within the formation. Hydrocarbon containing formations may contain water. Water present in the hydrocarbon containing formation will tend to further increase the amount of energy required to heat a hydrocarbon containing formation. In this manner, water tends to hinder efficient heating of the formation. For example, a large amount of energy may be required to evaporate water from a hydrocarbon containing formation.
Thus, an initial rate of temperature increase may be reduced by the presence of water in the formation.
Therefore, excessive amounts of heat and/or time may be required to heat a formation having a high moisture content to a temperature sufficient to allow pyrolysis of at least some of the hydrocarbons in the formation. In an embodiment, an in situ conversion process for hydrocarbons may include selecting a portion of the hydrocarbon containing formation for treatment having an initial moisture content of less than about 15% by weight (in some embodiments dewatering wells may be used to reduce the water content of the formation).

Alternatively, an in situ conversion process for hydrocarbons may include selecting a portion of the hydrocarbon containing formation for treatment having an initial moisture content of less than about 10% by weight.

In an embodiment, a hydrocarbon coritaining formation may be selected for treatment based on additional factors such as a thickness of hydrocarbon containing layer within the formation and assessed liquid production content. For example, a hydrocarbon containing formation may include multiple layers. Such layers may include hydrocarbon containing layers, and also layers that may be hydrocarbon free or have substantially low amounts of hydrocarbons. Each of the hydrocarbon containing layers may have a thickness that may vary depending on, for example, conditions under which the hydrocarbon containing layer was formed. Therefore, a hydrocarbon containing formation will typically be selected for treatment if that formation includes at least one hydrocarbon containing layer having a thickness sufficient for economical production of formation fluids.
A formation may also be chosen if the thickness of several layers that are closely spaced together is sufficient for economical production of formation fluids.
Other formations may also be chosen based on a richness of the hydrocarbon resource within the soil, even if the thickness of the resource is relatively thin.
In addition, a layer of a hydrocarbon containing formation may be selected for treatment based on a thickness of the hydrocarbon containing layer, and/or a total thickness of hydrocarbon containing layers in a formation. For example, an in situ conversion process for hydrocarbons may include selecting and treating a layer of a hydrocarbon containing formation having a thickness of greater than about 2 m, 3 m, and/or 5 m. In this manner, heat losses (as a fraction of total injected heat) to layers formed above and below a layer of hydrocarbons may be less than such heat losses from a thin layer of hydrocarbons. A process as described herein, however, may also include selecting and treating layers that may include layers substantially free of hydrocarbons and thin layers of hydrocarbons.
Each of the hydrocarbon containing layers may also have a potential formation fluid yield that may vary depending on, for example, conditions under which the hydrocarbon containing layer was formed, an amount of hydrocarbons in the layer, and/or a composition of hydrocarbons in the layer. A potential formation fluid yield may be measured, for example, by the Fischer Assay.
The Fischer Assay is a standard method which involves heating a sample of a hydrocarbon containing layer to approximately 500 C in one hour, collecting products produced from the heated sample, and quantifying the amount of products produced. A sample of a hydrocarbon containing layer may be obtained from a hydrocarbon containing formation by a method such as coring or any other sample retrieval method.

FIG. 3 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation. Heat sources 100 may be placed within at least a portion of the hydrocarbon containing formation. Heat sources 100 may include, for example, electrical heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 100 may also include other types of heaters. Heat sources 100 are configured to provide heat to at least a portion of a hydrocarbon containing formation. Energy may be supplied to the heat sources 100 through supply lines 102. The supply lines may be structurally different depending on the type of heat source or heat sources being used to heat the formation. Supply lines for heat sources may transmit electricity for electrical heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated within the formation.

Production wells 104 may be used to remove formation fluid from the formation. Formation fluid produced from the production wells 104 may be transported through collection piping 106 to treatment facilities 108.
Formation fluids may also be produced from heat sources 100. For example, fluid may be produced from heat sources 100 to control pressure within the formation adjacent to the heat sources. Fluid produced from heat sources 100 may be transported through tubing or piping to the collection piping 106 or the produced fluid may be transported through tubing or piping directly to the treatment facilities 108. The treatment facilities 108 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and other systems and units for processing produced formation fluids.

An in situ conversion system for treating hydrocarbons may include dewatering wells 110 (wells shown with reference number 110 may, in some embodiments, be capture and/or isolation wells). Dewatering wells 110 or vacuum wells may be configured to remove and inhibit liquid water from entering a portion of a hydrocarbon containing formation to be heated, or to a formation being heated. A plurality of water wells may surround all or a portion of a formation to be heated. In the embodiment depicted in FIG. 3, the dewatering wells 110 are shown extending only along one side of heat sources 100, but dewatering wells typically encircle all heat sources 100 used, or to be used, to heat the formation.

Dewatering wells 110 may be placed in one or more rings surrounding selected portions of the formation.

New dewatering wells may need to be installed as an area being treated by the in situ conversion process expands.
An outermost row of dewatering wells may inhibit a significant amount of water from flowing into the portion of formation that is heated or to be heated. Water produced from the outermost row of dewatering wells should be substantially clean, and may require little or no treatment before being released. An innermost row of dewatering wells may inhibit water that bypasses the outermost row from flowing into the portion of formation that is heated or to be heated. The innermost row of dewatering wells may also inhibit outward migration of vapour from a heated portion of the formation into surrounding portions of the formation. Water produced by the innermost row of dewatering wells may include some hydrocarbons. The water may need to be treated before being released. Alternately, water with hydrocarbons may be stored and used to produce synthesis gas from a portion of formation during a synthesis gas phase of the in situ conversion process. The dewatering wells may reduce heat loss to surrounding portions of the formation, may increase production of vapours from the heated portion, and may inhibit contamination of a water table proximate the heated portion of the formation.

In an alternative embodiment, a fluid (e.g., liquid or gas) may be injected in the innermost row of wells, allowing a selected pressure to be maintained in or about the pyrolysis zone. Additionally, this fluid may act as an isolation barrier between the outermost wells and the pyrolysis fluids, thereby improving the efficiency,of the dewatering wells.
The hydrocarbons to be treated may be located under a large area. The in situ conversion system may be used to treat small portions of the formation, and other sections of the formation may be treated as time progresses. In an embodiment of a system for treating an oil shale containing formation, a field layout for 24 years of development may be divided into 24 individual plots that represent individual drilling years. Each plot may include 120 "tiles" (repeating matrix patterns) wherein each tile is made of 6 rows by 20 columns. Each tile may include 1 production well and 12 or 18 heater wells. The heater wells may be placed in an equilateral triangle pattern with, for example, a well spacing of about 12 m.
Production wells may be located in centres of equilateral triangles of heater wells, or the production wells may be located approximately at a midpoint between two adjacent heater wells.

In certain embodiments, heat sources will be placed within a heater well formed within a hydrocarbon containing formation. The heater well may include an opening through an overburden of the formation and into at least one hydrocarbon containing section of the formation. Alternatively, as shown in FIG. 3a, heater well 224 may include an opening in formation 222 that may have a shape substantially similar to a helix or spiral.
A spiral configuration for a heater well may in some embodiments increase the transfer of heat from the heat source and/or allow the heat source to expand when heated, without buckling or other modes of failure.. In some embodiments, such a heater well may also include a substantially straight section through overburden 220.
Use of a straight heater well through the overburden may decrease heat loss to the overburden.
In an alternative embodiment, as shown in FIG. 3b, heat sources may be placed into heater well 224 that may include an opening in formation 222 having a shape substantially similar to a "U" (the "legs" of the "U" may be wider or more narrow depending on the embodiments used). First portion 226 and third portion 228 of heater well 224 may be arranged substantially perpendicular to an upper surface of formation 222. In addition, the first and the third portion of the heater well may extend substantially vertically through overburden 220. Second portion 230 of heater well 224 may be substantially parallel to the upper surface of the formation.

In addition, multiple heat sources (e.g., 2, 3, 4, 5, 10 heat sources or more) may extend from a heater well in some situations. For example, as shown in FIG. 3c, heat sources 232, 234, and 236 may extend through overburden 220 into formation 222 from heater well 224.
Such situations may occur when surface considerations (e.g., aesthetics, surface land use concerns, and/or unfavourable soil conditions near the surface) make it desirable to concentrate the surface facilities in fewer locations. For example, in areas where the soil is frozen and/or marshy it may be more cost-effective to have surface facilities located in a more centralized location.

In certain embodiments a first portion of a heater well may extend from a surface of the ground, through an overburden, and into a hydrocarbon containing formation.
A second portion of the heater well may include one or more heater wells in the hydrocarbon containing formation. The one or more heater wel's may be disposed within the hydrocarbon containing formation at various angles. In some embodiments, at least one of heater wells may be disposed substantially parallel to a boundary of the hydrocarbon containing formation. In alternate embodiments, at least one of the heater wells may be substantially perpendicular to the hydrocarbon containing formation. In addition, one of the one or more heater wells may be positioned at an angle between perpendicular and parallel to a layer in the formation.
FIG. 4 illustrates an embodiment of a hydrocarbon containing formation 200 that may be at a substantially near-horizontal angle with respect to an upper surface of the ground 204. An angle of hydrocarbon containing formation 200, however, may vary. For example, hydrocarbon containing formation 200 may be steeply dipping. Economically viable production of a steeply dipping hydrocarbon containing formation may not be possible using presently available mining methods. A
relatively steeply dipping hydrocarbon containing formation, however, may be subjected to an in situ conversion process as described herein. For example, a single set of gas producing wells may be disposed near a top of a steeply dipping hydrocarbon containing formation. Such a formation may be heated by heating a portion of the formation proximate a top of the hydrocarbon containing formation and sequentially heating lower sections of the hydrocarbon containing formation.

Gases may be produced from the hydrocarbon containing formation by transporting gases through the previously pyrolyzed hydrocarbons with minimal pressure loss.

In an embodiment, an in situ conversion process for hydrocarbons may include providing heat to at least a portion of a hydrocarbon containing foimation that dips in sections. For example, a portion of the formation may include a dip that may include a minimum depth of the portion. A production well may be located in the portion of the hydrocarbon containing formation proximate the minimum depth. An additional production well may not be required in the portion. For example, as heat transfers through the hydrocarbon containing formation and at least some hydrocarbons in the portion pyrolyze, pyrolyzation fluids formed in the portion may travel through pyrolyzed sections of the hydrocarbon containing formation to the production well. As described herein, increased permeability due to in situ treatment of a hydrocarbon containing formation may increase transfer of vapours through the treated portion of the formation. Therefore, a number of production wells required to produce a mixture from the formation may be reduced. Reducing the number of production wells required for production may increase economic viability of an in situ conversion process.

In steeply dipping formations, directional drilling may be used to form an opening for a heater well in the formation. Directional drilling may include drilling an opening in which the route/course of the opening may be planned before drilling. Such an opening may usually be drilled with rotary equipment. In directional drilling, a route/course of an opening may be controlled by deflection wedges, etc.

Drilling heater well 202 may also include drilling an opening in the formation with a drill equipped with a steerable motor and an accelerometer that may be configured to follow hydrocarbon containing formation 200. For example, a steerable motor may be configured to maintain a substantially constant distance between heater well 202 and a boundary of hydrocarbon containing formation 200 throughout drilling of the opening. Drilling of heater well 202 with the steerable motor and the accelerometer may be relatively economical.
Alternatively, geosteered drilling may be used to drill heater well 202 into hydrocarbon containing formation 200. Geosteered drilling may include determining or estimating a distance from an edge of hydrocarbon containing formation 200 to heater well 202 with a sensor. The sensor may include, but may not be limited to, sensors that may be configured to determine a distance from an edge of hydrocarbon containing formation 200 to heater well 202. In addition, such a sensor may be configured to determine and monitor a variation in a characteristic of the hydrocarbon containing formation 200. Such sensors may include, but may not be limited to, sensors that may be configured to measure a characteristic of a hydrocarbon seam using resistance, gamma rays, acoustic pulses, and/or other devices. Geosteered drilling may also include forming an opening for a heater well with a drilling apparatus that may include a steerable motor. The motor may be controlled to maintain a predetermined distance from an edge of a hydrocarbon containing formation. In an additional embodiment, drilling of a heater well or any other well in a formation may also include sonic drilling.

FIG. 5 illustrates an embodiment of a plurality of heater wells 210 formed in hydrocarbon containing formation 212. Hydrocarbon containing formation 212 may be a steeply dipping formation. One or more of the heater wells 210 may be formed in the formation such that two or more of the heater wells are substantially parallel to each other, and/or such that at least one heater well is substantially parallel to hydrocarbon containing formation 212. For example, one or more of the heater wells 210 may be formed in hydrocarbon containing formation 212 by a magnetic steering method.
An example of a magnetic steering method is illustrated in U.S. Patent No. 5,676,212 to Kuckes, which is incorporated by reference as if fully set forth herein.
Magnetic steering may include drilling heater well 210 parallel to an adjacent heater well. The adjacent well may have been previously drilled. In addition, magnetic steering may include directing the drilling by sensing and/or determining a magnetic field produced in an adjacent heater well. For example, the magnetic field may be produced in the adjacent heater well by flowing a current through an insulated current-carrying wireline disposed in the adjacent heater well. Alternatively, one or more of the heater wells 210 may be formed by a method as is otherwise described herein. A spacing between heater wells 210 may be determined according to any of the embodiments described herein.
In some embodiments, heated portion 310 may extend substantially radially from heat source 300, as shown in FIG. 6. For example, a width of heated portion 310, in a direction extending radially from heat source 300, may be about 0 m to about 10 m. A width of heated portion 310 may vary, however, depending upon, for example, heat provided by heat source 300 and the characteristics of the formation. Heat provided by heat source 300 will typically transfer through the heated portion to create a temperature gradient within the heated portion. For example, a temperature proximate the heater well will generally be higher than a temperature proximate an outer lateral boundary of the heated portion. A temperature gradient within the heated portion, however, may vary within the heated portion depending on, for example, the thermal conductivity of the formation.
As heat transfers through heated portion 310 of the hydrocarbon containing formation, a temperature within at least a section of the heated portion may be within a pyrolysis temperature range. In this manner, as the heat transfers away from the heat source, a front at which pyrolysis occurs will in many instances travel outward from the heat source. For example, heat from the heat source may be allowed to transfer into a selected section of the heated portion such that heat from the heat source pyrolyzes at least some of the hydrocarbons within the selected section. As such, pyrolysis may occur within selected section 315 of the heated portion, and pyrolyzation fluids will be generated from hydrocarbons in the selected section. An inner lateral boundary of selected section 315 may be radially spaced from the heat source. For example, an inner lateral boundary of selected section 315 may be radially spaced from the heat source by about 0 m to about 1 m. In addition, selected section 315 may have a width radially extending from the inner lateral boundary of the selected section. For example, a width of the selected section may be at least approximately 1.5 m, at least approximately 2.4 m, or even at least approximately 3.0 m. A width of the selected section, however, may also be greater than approximately 1.5 m and less than approximately 10 m.
After pyrolyzation of hydrocarbons in a portion of the selected section is complete, a section of spent hydrocarbons 317 may be generated proximate to the heat source.

In some embodiments, a plurality of heated portions may exist within a unit of heat sources. A unit of heat sources refers to a minimal number of heat sources that form a template that may be repeated to create a pattern of heat sources within the formation. The heat sources may be located within the formation such that superposition (overlapping) of heat produced from the heat sources is effective. For example, as illustrated in FIG. 7, transfer of heat from two or more heat sources 330 results in superposition of heat 332 to be effective within an area defined by the unit of heat sources. Superposition may also be effective within an interior of a region defined by two, three, four, five, six or more heat sources. For example, an area in which superposition of heat 332 is effective includes an area to which significant heat is transferred by two or more heat sources of the unit of heat sources. An area in which superposition of heat is effective may vary depending upon, for example, the spacings between heat sources.
Superposition of heat may increase a temperature in at least a portion of the formation to a temperature sufficient for pyrolysis of hydrocarbon within the portion. In this manner, superposition of heat 332 tends to increase the amount of hydrocarbon in a formation that may be pyrolyzed. As such, a plurality of areas that are within a pyrolysis temperature range may exist within the unit of heat sources. The selected sections 334 may include areas at a pyrolysis temperature range due to heat transfer from only one heat source, as well as areas at a pyrolysis temperature range due to superposition of heat.

In addition, a pattern of heat sources will often include a plurality of units of heat sources. There will typically be a plurality of heated portions, as well as selected sections within the pattern of heat sources.
The plurality of heated portions and selected sections may be configured as described herein. Superposition of heat within a pattern of heat sources may decrease the time necessary to reach pyrolysis temperatures within the multitude of heated portions. Superposition of heat may allow for a relatively large spacing between adjacent heat sources, which may in turn provide a relatively slow rate of heating of the hydrocarbon containing formation.
In certain embodiments, superposition of heat will also generate fluids substantially uniformly from a heated portion of a hydrocarbon containing formation.
In certain embodiments, a majority of pyrolysis fluids may be produced when the selected section is within a range from about 0 m to about 25 m from a heat source.
As shown in FIG. 3, in addition to heat sources 100, one or more production wells 102 will typically be disposed within the portion of the hydrocarbon containing formation. Production well 102 may be configured such that a mixture that may include formation fluids may be produced through the production well. Production well 102 may also include a heat source. In this manner, the formation fluids may be maintained at a selected temperature throughout production, thereby allowing more or all of the formation fluids to be produced as vapours.
Therefore high temperature pumping of liquids from the production well may be reduced or substantially eliminated, which in turn decreases production costs.
Providing heating at or through the production well tends to: (1) prevent condensation and/or reiluxing of production fluid when such production fluid is moving in the production well proximate to the overburden, (2) increase heat input into the formation, and/or (3) increase formation permeability at or proximate the production well.

Because permeability and/or porosity increase in the heated formation, produced vapours may flow considerable distances through the formation with relatively little pressure differential. Therefore, in some embodiments, production wells may be provided near an upper surface of the formation. Increases in permeability may result from a reduction of mass of the heated portion due to vaporization of water, removal of hydrocarbons, and/or creation of fractures. In this manner, fluids may more easily flow through the heated portion.
For example, fluid generated within a hydrocarbon containing formation may move a considerable distance through the hydrocarbon containing formation as a vapour.
Such a considerable distance may include, for example, about 50 m to about 1000 m. The vapour may have a relatively small pressure drop across the considerable distance due to the permeability of the heated portion of the formation. In addition, due to such permeability, a production well may only need to be provided in every other unit of heat sources or every third, fourth, fifth, sixth units of heat sources. Furthermore, as shown in FIG. 4, production wells 206 may extend through a hydrocarbon containing formation near the top of heated portion 208.

Embodiments of production well 102 may include valves configured to alter, maintain, and/or control a pressure of at least a portion of the formation. Production wells may be cased wells that may have production screens or perforated casings adjacent to production zones. In addition, the production wells may be surrounded by sand, gravel or other packing material adjacent to production zones. Furthermore, production wells 102 may be coupled to treatment section 108, as shown in FIG. 3. Treatment section 108 may include any of the surface facilities as described herein.

In addition, water pumping wells or vacuum wells may be configured to remove liquid water from a portion of a hydrocarbon containing formation to be heated. Water removed from the formation may be used on the surface, and/or monitored for water quality. For example, a plurality of water wells may surround all or a portion of a formation to be heated. The plurality of water wells may be configured in one or more rings surrounding the portion of the formation. An outermost row of water wells may inhibit a significant amount of water from flowing into the portion to be heated. An innermost row of water wells may inhibit water that bypasses the outermost row from flowing into the portion to be heated.
The innermost row of water wells may also inhibit outward migration of vapour from a heated portion of the formation into surrounding portions of the formation. In this manner, the water wells may reduce heat loss to surrounding portions of the formation, may increase production of vapours from the heated portion, and may inhibit contamination of a water table proximate to the heated portion of the formation. In some embodiments pressure differences between successive rows of dewatering wells may be minimized (e.g., maintained or near zero) to create a"no or low flow" boundary between rows.
In certain embodiments, wells initially used for one purpose may be later used for one or more other purposes, thereby lowering project costs and/or decreasing the time required to perform certain tasks. For instance, production wells (and in some circumstances heater wells) may initially be used as dewatering wells (e.g., before heating is begun and/or when heating is initially started). In addition, in some circumstances dewatering wells can later be used as production wells (and in some circumstances heater wells). As such, the dewatering wells may be placed and/or designed so that such wells can be later used as production wells and/or heater wells. The heater wells may be placed and/or designed so that such wells can be later used as production wells and/or dewatering wells. The production wells may be placed and/or designed so that such wells can be later used as dewatering wells and/or heater wells. Similarly, injection wells may be wells 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, monitoring wells may be wells that initially were used for other purposes (e.g., heating, production, dewatering, injection, etc.), and monitoring wells may later be used for other purposes.
FIG. 8 illustrates a pattern of heat sources 400 and production wells 402 that may be configured to treat a hydrocarbon containing formation, Heat sources 400 may be arranged in a unit of heat sources such as triangular pattern 401. Heat sources 400, however, may be arranged in a variety of patterns including, but not limited to, squares, hexagons, and other polygons. The pattern may include a regular polygon to promote uniform heating through at least the portion of the formation in which the heat sources are placed. The pattern may also be a line drive pattern. A line drive pattern generally includes a first linear array of heater wells, a second linear array of heater wells, and a production well or a linear array of production wells between the first and second linear array of heater wells.
A distance from a node of a polygon to a centroid of the polygon is smallest for a 3 sided polygon and increases with increasing number of sides of the polygon.
The distance from a node to the centroid for an equilateral triangle is (length/2)/(square root(3)/2) or 0.5774 times the length. For a square, the distance from a node to the centroid is (length/2)/(square root(2)/2) or 0.7071 times the length. For a hexagon, the distance from a node to the centroid is (length/2)(1/2) or the length. The difference in distance between a heat source and a mid point to a second heat sources (length/2) and the distance from a heat source to the centroid for an equilateral pattern (0.5774 times the length) is significantly less for the equilateral triangle pattern than for any higher order polygon pattern. The small difference means that superposition of heat may develop more rapidly and that formation between heat sources may rise to a substantially more uniform temperature using an equilateral triangle pattern rather than a higher order polygon pattern.
Triangular patterns tend to provide more uniform heating to a portion of the formation in comparison to _ 77 _ other patterns such as squares and/or hexagons.
Triangular patterns tend to provide faster heating to a predetermined temperature in comparison to other patterns such as squares and/or hexagons. Triangle patterns may also result in a small volume of the portion that are overheated. A plurality of units of heat sources such as triangular pattern 401 may be arranged substantially adjacent to each other to form a repetitive pattern of units over an area of the formation. For example, triangular patterns 401 may be arranged substantially adjacent to each other in a repetitive pattern of units by inverting an orientation of adjacent triangles 401.
Other patterns of heat sources 400 may also be arranged such that smaller patterns may be disposed adjacent to each other to form larger patterns.
Production wells may be disposed in the formation in a repetitive pattern of units. In certain embodiments, production well 402 may be disposed proximate to a centre of every third triangle 401 arranged in the pattern.
Production well 402, however, may be disposed in every triangle 401 or within just a few triangles. A
production well may be placed within every 13, 20, or 30 heater well triangles. For example, a ratio of heat sources in the repetitive pattern of units to production wells in the repetitive pattern of units may be more than approximately 5 (e.g., more than 6, 7, 8, or 9). In addition, the placement of production well 402 may vary depending on the heat generated by one or more heat sources 400 and the characteristics of the formation (such as permeability). Furthermore, three or more production wells may be located within an area defined by a repetitive pattern of units. For example, as shown in FIG. 8, production wells 410 may be located within an area defined by repetitive pattern of units 412.
Production wells 410 may be located in the formation in a unit of production wells. For example, the unit of production wells may be a triangular pattern. Production wells 410, however, may be disposed in another pattern within repetitive pattern of units 412.
In addition, one or more injection wells may be disposed within a repetitive pattern of units. The injection wells may be configured as described herein.
For example, as shown in FIG. 8, injection wells 414 may be located within an area defined by repetitive pattern of units 416. Injection wells 414 may also be located in the formation in a unit of injection wells. For example, the unit of injection wells may be a triangular pattern.
Injection wells 414, however, may be disposed in any other pattern as described herein. In certain embodiments, one or more production wells and one or more injection wells may be disposed in a repetitive pattern of units. For example, as shown in FIG. 8, production wells 418 and injection wells 420 may be located within an area defined by repetitive pattern of units 422.
Production wells 418 may be located in the formation in a unit of production wells, which may be arranged in a first triangular pattern. In addition, injection wells 420 may be located within the formation in a unit of production wells, which may be arranged in a second triangular pattern. The first triangular pattern may be substantially different than the second triangular pattern. For example, areas defined by the first and second triangular patterns may be substantially different.
In addition, one or more monitoring wells may be disposed within a repetitive pattern of units. The monitoring wells may be configured as described herein.
For example, the wells may be configured with one or more devices that measure a temperature, a pressure, and/or a property of a fluid. In some embodiments, logging tools may be placed in monitoring well wellbores to measure properties within a formation. The logging tools may be moved to other monitoring well wellbores as needed. The monitoring well wellbores may be cased or uncased wellbores. As shown in FIG. 8, monitoring wells 424 may be located within an area defined by repetitive pattern of units 426. Monitoring wells 424 may be located in the formation in a unit of monitoring wells, which may be arranged in a triangular pattern. Monitoring wells 424, however, may be disposed in any of the other patterns as described herein within repetitive pattern of units 426.
It is to be understood that a geometrical pattern of heat sources 400 and production wells 402 is described herein by example. A pattern of heat sources and production wells will in many instances vary depending on, for example, the type of hydrocarbon containing formation to be treated. For example, for relatively thin layers heating wells may be aligned along one or more layers along strike or along dip. For relatively thick layers, heat sources may be configured at an angle to one or more layers (e.g., orthogonally or diagonally).
A triangular pattern of heat sources may be configured to treat a hydrocarbon containing formation having a thickness of about 10 meters or more. For a thinner hydrocarbon containing formation, e.g., about 10 meters thick or less, a line and/or staggered line pattern of heat sources may be configured to treat the hydrocarbon containing formation.

For certain thinner formations, heating wells may be placed closer to an edge of the formation (e.g., in a staggered line instead of line placed in the centre of the layer) of the formation to increase the amount of hydrocarbons produced per unit of energy input. A
portion of input heating energy may heat non-hydrocarbon containing formation, but the staggered pattern may allow superposition of heat to heat a majority of the hydrocarbon formation to pyrolysis temperatures. If the thin formation is heated by placing in the formation along a centre of the thickness, a significant portion of the hydrocarbon containing formation may not be heated to pyrolysis temperatures. In some embodiments, placing heater wells closer to an edge of the formation may increase the volume of formation undergoing pyrolysis per unit of energy input.

In addition, the location of production well 402 within a pattern of heat sources 400 may be determined by, for example, a desired heating rate of the hydrocarbon containing formation, a heating rate of the heat sources, the type of heat sources used, the type of hydrocarbon containing formation (and its thickness), the composition of the hydrocarbon containing formation, the desired composition to be produced from the formation, and/or a desired production rate. Exact placement of heater wells, production wells, etc. will depend on variables specific to the formation (e.g., thickness of the layer, composition of the layer, etc.), project economics, etc. In certain embodiments heater wells may be substantially horizontal while production wells may be vertical, or vice versa.

Any of the wells described herein may be aligned along dip or strike, or oriented at an angle between dip and strike.

The spacing between heat sources may also vary depending on a number of factors that may include, but are not limited to, the type of a hydrocarbon containing formation, the selected heating rate, and/or the selected average temperature to be obtained within the heated portion. For example, the spacing between heat sources may be within a range of about 5 m to about 25 m.
Alternatively, the spacing between heat sources may be within a range of about 8 m to about 15 m.
The spacing between heat sources may influence the composition of fluids produced from a hydrocarbon containing formation. In an embodiment, a computer-implemented method may be used to determine optimum heat source spacings within a hydrocarbon containing formation. For example, at least one property of a portion of hydrocarbon containing formation can usually be measured. The measured property may include, but is not limited to, vitrinite reflectance, hydrogen content, atomic hydrogen to carbon ratio, oxygen content, atomic oxygen to carbon ratio, water content, thickness of the hydrocarbon containing formation, and/or the amount of stratification of the hydrocarbon containing formation into separate layers of rock and hydrocarbons.
In certain embodiments a computer-implemented method may include providing at least one measured property to a computer system. One or more sets of heat source spacings in the formation may also be provided to the computer system. For example, a spacing between heat sources may be less than about 30 m. Alternatively, a spacing between heat sources may be less than about 15 m.

The method may also include determining properties of fluids produced from the portion as a function of time for each set of heat source spacings. The produced fluids include, but are not limited to, formation fluids such as pyrolyzation fluids and synthesis gas. The determined properties may include, but are not limited to, API gravity, carbon number distribution, olefin content, hydrogen content, carbon monoxide content, and/or carbon dioxide content. The determined set of properties of the produced fluid may be compared to a set of selected properties of a produced fluid. In this manner, sets of properties that match the set of selected properties may be determined. Furthermore, heat source spacings may be matched to heat source spacings associated with desired properties.
Unit cell 404 will often include a number of heat sources 400 disposed within a formation around each production well 402. An area of unit cell 404 may be determined by midlines 406 that may be equidistant and perpendicular to a line connecting two production wells 402. Vertices 408 of the unit cell may be at the intersection of two midlines 406 between production wells 402. Heat sources 400 may be disposed in any arrangement within the area of unit cell 404. For example, heat sources 400 may be located within the formation such that a distance between each heat source varies by less than approximately 10%, 20%, or 30%. In addition, heat sources 400 may be disposed such that an approximately equal space exists between each of the heat sources. Other arrangements of heat sources 400 within unit cell 404, however, may be used depending on, for example, a heating rate of each of the heat sources. A
ratio of heat sources 400 to production wells 402 may be determined by counting the number of heat sources 400 and production wells 402 within unit cell 404, or over the total field.

FIG. 9 illustrates an embodiment of unit cell 404.
Unit cell 404 includes heat sources 400 and production wells 402. Unit cell 404 may have six full heat sources 400a and six partial heat sources 400b. Full heat sources 400a may be closer to production well 402 than partial heat sources 400b. In addition, an entirety of each of the full heat sources 400 may be located within unit cell 404. Partial heat sources 400b may be partially disposed within unit cell 404. Only a portion of heat source 400b disposed within unit cell 404 may be configured to provide heat to a portion of a hydrocarbon containing formation disposed within unit cell 404. A
remaining portion of heat source 400b disposed outside of unit cell 404 may be configured to provide heat to a remaining portion of the hydrocarbon containing formation outside of unit cell 404. Therefore, to determine a number of heat sources within unit cell 404 partial heat source 400b may be counted as one-half of full heat sources 400. In other unit cell embodiments, fractions other than 1/2 (e.g. 1/3) may more accurately describe the amount of heat applied to a portion from a partial heat source.

The total number of heat sources 400 in unit cell 404 may include six full heat sources 400a that are each counted as one heat source, and six partial heat sources 400b that are each counted as one half of a heat source. Therefore, a ratio of heat sources 400 to production wells 402 in unit cell 404 may be determined as 9:1. A ratio of heat sources to production wells may vary, however, depending on, for example, the desired heating rate of the hydrocarbon containing formation, the heating rate of the heat sources, the type of heat source, the type of hydrocarbon containing formation, the composition of hydrocarbon containing formation, the desired composition of the produced fluid, and/or the desired production rate. Providing more heat sources wells per unit area will allow faster heating of the selected portion and thus hastening the onset of production, however more heat sources will generally cost more money to install. An appropriate ratio of heat sources to production wells may also include ratios greater than about 5:1, and ratios greater than about 7:1. In some embodiments an appropriate ratio of heat sources to production wells may be about 10:1, 20:1, 50:1 or greater. If larger ratios are used, then project costs tend to decrease since less wells and equipment are needed.

A "selected section" would generally be the volume of formation that is within a perimeter defined by the location of the outermost heat sources (assuming that the formation is viewed from above). For example, if four heat sources were located in a single square pattern with an area of about 100 m2 (with each source located at a corner of the square), and if the formation had an average thickness of approximately 5 m across this area, then the selected section would be a volume of about 500 m3 (i.e., the area multiplied by the average formation thickness across the area). In many commercial applications, it is envisioned that many (e.g., hundreds or thousands) heat sources would be adjacent to each other to heat a selected section, and therefore in such cases only the outermost (i.e., the "edge") heat sources would define the perimeter of the selected section.

A heat source may include, but is not limited to, an electric heater or a combustion heater. The electric heater may include an insulated conductor, an elongated member disposed in the opening, and/or a conductor disposed in a conduit. Such an electric heater may be configured according to any of the embodiments described herein.

In an embodiment, a hydrocarbon containing formation may be heated with a natural distributed combustor system located in the formation. The generated heat may be allowed to transfer to a selected section of the formation to heat it.

A temperature sufficient to support oxidation may be, for example, at least about 200 C or 250 C. The temperature sufficient to support oxidation will tend to vary, however, depending on, for example, a composition of the hydrocarbons in the hydrocarbon containing formation, water content of the formation, and/or type and amount of oxidant. Some water may be removed from the formation prior to heating. For example, the water may be pumped from the formation by dewatering wells.
The heated portion of the formation may be near or substantially adjacent to an opening in the hydrocarbon containing formation. The opening in the formation may be a heater well formed in the formation. The heater well may be formed as in any of the embodiments described herein. The heated portion of the hydrocarbon containing formation may extend radially from the opening to a width of about 0.3 m to about 1.2 m. The width, however, may also be less than about 0.9 m. A width of the heated portion may vary. In certain embodiments the variance will depend on, for example, a width necessary to generate sufficient heat during oxidation of carbon to maintain the oxidation reaction without providing heat from an additional heat source.

After the portion of the formation reaches a temperature sufficient to support oxidation, an oxidizing fluid may be provided into the opening to oxidize at least a portion of the hydrocarbons at a reaction zone, or a heat source zone, within the formation. Oxidation of the hydrocarbons will generate heat at the reaction zone. The generated heat will in most embodiments transfer from the reaction zone to a pyrolysis zone in the formation. In certain embodiments the generated heat will transfer at a rate between about 650 watts per meter as measured along a depth of the reaction zone, and/or 1650 watts per meter as measured along a depth of the reaction zone. Upon oxidation of at least some of the hydrocarbons in the formation, energy supplied to the heater for initially heating may be reduced or may be turned off. As such, energy input costs may be significantly reduced, thereby providing a significantly more efficient system for heating the formation.
In an embodiment, a conduit may be disposed in the opening to provide the oxidizing fluid into the opening.
The conduit may have flow orifices, or other flow control mechanisms (i.e., slits, venturi meters, valves, etc.) to allow the oxidizing fluid to enter the opening. The term "orifices" includes openings having a wide variety of cross-sectional shapes including, but not limited to, circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes. The flow orifices may be critical flow orifices in some embodiments. The flow orifices may be configured to provide a substantially constant flow of oxidizing fluid into the opening, regardless of the pressure in the opening.
In some embodiments, the number of flow orifices, which may be formed in or coupled to the conduit, may be limited by the diameter of the orifices and a desired spacing between orifices for a length of the conduit.
For example, as the diameter of the orifices decreases, the number of flow orifices may increase, and vice versa.
In addition, as the desired spacing increases, the number of flow orifices may decrease, and vice versa. The diameter of the orifices may be determined by, for example, a pressure in the conduit and/or a desired flow rate through the orifices. For example, for a flow rate of about 1.7 standard cubic meters per minute and a pressure of about 7 bar absolute, an orifice diameter may be about 1.3 mm with a spacing between orifices of about 2 m.

Smaller diameter orifices may plug more easily than larger diameter orifices due to, for example, contamination of fluid in the opening or solid deposition within or proximate to the orifices. In some embodiments, the number and diameter of the orifices can be chosen such that a more even or nearly uniform heating profile will be obtained along a depth of the formation within the opening. For example, a depth of a heated formation that is intended to have an approximately uniform heating profile may be greater than about 300 m, or even greater than about 600 m. Such a depth may vary, however, depending on, for example, a type of formation to be heated and/or a desired production rate.
In some embodiments, flow orifices may be disposed in a helical pattern around the conduit within the opening.
The flow orifices may be spaced by about 0.3 m to about 3 m between orifices in the helical pattern. In some embodiments, the spacing may be about 1 m to about 2 m or, for example, about 1.5 m.

The flow of the oxidizing fluid into the opening may be controlled such that a rate of oxidation at the reaction zone is controlled. Transfer of heat between incoming oxidant and outgoing oxidation products may heat the oxidizing fluid. The transfer of heat may also maintain the conduit below a maximum operating temperature of the conduit.

FIG. 10 illustrates an embodiment of a natural distributed combustor configured to heat a hydrocarbon containing formation. Conduit 512 may be placed into opening 514 in formation 516. Conduit 512 may have inner conduit 513. Oxidizing fluid source 508 may provide oxidizing fluid 517 into inner conduit 513. Inner conduit 513 may have critical flow orifices 515 along its length. Critical flow orifices 515 may be disposed in a helical pattern (or any other pattern) along a length of inner conduit 513 in opening 514. For example, critical flow orifices 515 may be arranged in a helical pattern with a distance of about 1 m to about 2.5 m between adjacent orifices. Critical flow orifices 515 may be further configured as described herein. Inner conduit 513 may be sealed at the bottom. Oxidizing fluid 517 may be provided into opening 514 through critical flow orifices 515 of inner conduit 513.

Critical flow orifices 515 may be designed such that substantially the same flow rate of oxidizing fluid 517 may be provided through each critical flow orifice.
Critical flow orifices 515 may also provide substantially uniform flow of oxidizing fluid 517 along a length of conduit 512. Such flow may provide substantially uniform heating of formation 516 along the length of conduit 512.
Packing material 542 may enclose conduit 512 in overburden 540 of the formation. Packing material 542 may substantially inhibit flow of fluids from opening 514 to surface 550. Packing material 542 may include any material configurable to inhibit flow of fluids to surface 550 such as cement, sand, and/or gravel.
Typically a conduit or an opening in the packing remains to provide a path for oxidation products to reach the surface.

Oxidation products 519 typically enter conduit 512 from opening 514. Oxidation products 519 may include carbon dioxide, oxides of nitrogen, oxides of sulphur, carbon monoxide, and/or other products resulting from a reaction of oxygen with hydrocarbons and/or carbon.
Oxidation products 519 may be removed through conduit 512 to surface 550. Oxidation product 519 may flow along a face of reaction zone 524 in opening 514 until proximate an upper end of opening 514 where oxidation product 519 may flow into conduit 512. Oxidation products 519 may also be removed through one or more conduits disposed in opening 514 and/or in formation 516. For example, oxidation products 519 may be removed through a second conduit disposed in opening 514. Removing oxidation products 519 through a conduit may substantially inhibit oxidation products 519 from flowing to a production well disposed in formation 516. Critical flow orifices 515 may also be configured to substantially inhibit oxidation products 519 from entering inner conduit 513.
A flow rate of oxidation product 519 may be balanced with a flow rate of oxidizing fluid 517 such that a substantially constant pressure is maintained within opening 514. For a 100 m length of heated section, a flow rate of oxidizing fluid may be between about 0.5 standard cubic meters per minute to about 5 standard cubic meters per minute, or about 1.0 standard cubic meters per minute to about 4.0 standard cubic meters per minute, or, for example, about 1.7 staridard cubic meters per minute. A flow rate of oxidizing fluid into the formation may be incrementally increased during use to accommodate expansion of the reaction zone. A pressure in the opening may be, for example, about 8 bar absolute.
Oxidizing fluid 517 may oxidize at least a portion of the hydrocarbons in heated portion 518 of hydrocarbon containing formation 516 at reaction zone 524. Heated portion 518 may have been initially heated to a temperature sufficient to support oxidation by an electric heater, as shown in FIG. 14, or by any other suitable system or method described herein. In some embodiments, an electric heater may be placed inside or strapped to the outside of conduit 513.

In certain embodiments it is beneficial to control the pressure within the opening 514 such that oxidation product and/or oxidation fluids are inhibited from flowing into the pyrolysis zone of the formation. In some instances pressure within opening 514 will be balanced with pressure within the formation to do so.
Although the heat from the oxidation is transferred to the formation, oxidation product 519 (and excess oxidation fluid such as air) may be substantially inhibited from flowing through the formation and/or to a production well within formation 516. Instead oxidation product 519 (and excess oxidation fluid) is removed (e.g., through a conduit such as conduit 512) as is described herein. In this manner, heat is transferred to the formation from the oxidation but exposure of the pyrolysis zone with oxidation product 519 and/or oxidation fluid may be substantially inhibited and/or prevented.

In certain embodiments, some pyrolysis product near the reaction zone 524 may also be oxidized in reaction zone 524 in addition to the carbon. Oxidation of the pyrolysis product in reaction zone 524 may provide additional heating of formation 516. When such oxidation of pyrolysis product occurs, it is desirable that oxidation product from such oxidation be removed (e.g., through a conduit such as conduit 512) near the reaction zone as is described herein, thereby inhibiting contamination of other pyrolysis product in the formation with oxidation product.

Conduit 512 may be configured to remove oxidation product 519 from opening 514 in formation 516. As such, oxidizing fluid 517 in inner conduit 513 may be heated by heat exchange in overburden section 540 from oxidation product 519 in conduit 512. Oxidation product 519 may be cooled by transferring heat to oxidizing fluid 517. In this manner, oxidation of hydrocarbons within formation 516 may be more thermally efficient.
Oxidizing fluid 517 may transport through reaction zone 524, or heat source zone, by gas phase diffusion and/or convection. Diffusion of oxidizing fluid 517 through reaction zone 524 may be more efficient at the relatively high temperatures of oxidation. Diffusion of oxidizing fluid 517 may inhibit development of localized overheating and fingering in the formation. Diffusion of oxidizing fluid 517 through formation 516 is generally a mass transfer process. In the absence of an external force, a rate of diffusion for oxidizing fluid 517 may depend upon concentration, pressure, and/or temperature of oxidizing fluid 517 within formation 516. The rate of diffusion may also depend upon the diffusion coefficient of oxidizing fluid 517 through formation 516. The diffusion coefficient may be determined by measurement or calculation based on the kinetic theory of gases. In general, random motion of oxidizing fluid 517 may transfer oxidizing fluid 517 through formation 516 from a region of high concentration to a region of low concentration.

With time, reaction zone 524 may slowly extend radially to greater diameters from opening 514 as hydrocarbons are oxidized. Reaction zone 524 may, in many embodiments, maintain a relatively constant width.

For example, reaction zone 524 may extend radially at a rate of less than about 0.91 m per year for a hydrocarbon containing formation. For example, for a coal containing formation, reaction zone 524 may extend radially at a rate between about 0.5 m per year to about 1 m per year.
For an oil shale containing formation, reaction zone 524 may extend radially about 2 m in the first year and at a lower rate in subsequent years due to an increase in volume of reaction zone 524 as reaction zone 524 extends radially. Such a lower rate may be about 1 m per year to about 1.5 m per year. Reaction zone 524 may extend at slower rates for hydrocarbon rich formations (e.g., coal) and at faster rates for formations with more inorganic material in it (e.g., oil shale) since more hydrocarbons per volume are available for combustion in the hydrocarbon rich formations.

A flow rate of oxidizing fluid 517 into opening 514 may be increased as a diameter of reaction zone 524 increases to maintain the rate of oxidation per unit volume at a substantially steady state. Thus, a temperature within reaction zone 524 may be maintained substantially constant in some embodiments. The temperature within reaction zone 524 may be between about 650 C to about 900 C or, for example, about 760 C.
The temperature may be maintained below a temperature that results in production of oxides of nitrogen (NOx).

The temperature within reaction zone 524 may vary depending on, for example, a desired heating rate of selected section 526. The temperature within reaction zone 524 may be increased or decreased by increasing or decreasing, respectively, a flow rate of oxidizing fluid 517 into opening 514. A temperature of conduit 512, inner conduit 513, and/or any metallurgical materials within opening 514 typically will not exceed a maximum operating temperature of the material.
Maintaining the temperature below the maximum operating temperature of a material may inhibit excessive deformation and/or corrosion of the material.
An increase in the diameter of reaction zone 524 may allow for relatively rapid heating of the hydrocarbon containing formation 516. As the diameter of reaction zone 524 increases, an amount of heat generated per time in reaction zone 524 may also increase. Increasing an amount of heat generated per time in the reaction zone will in many instances increase heating rate of the formation 516 over a period of time, even without increasing the temperature in the reaction zone or the temperature at conduit 513. Thus, increased heating may be achieved over time without installing additional heat sources, and without increasing temperatures adjacent to wellbores. In some embodiments the heating rates may be increased while allowing the temperatures to decrease (allowing temperatures to decrease may often lengthen the life of the equipment used).

By utilizing the carbon in the formation as a fuel, the natural distributed combustor may save significantly on energy costs. Thus, an economical process may be provided for heating formations that may otherwise be economically unsuitable for heating by other methods.
Also, fewer heaters may be placed over an extended area of formation 516. This may provide for a reduced equipment cost associated with heating the formation 516.
The heat generated at reaction zone 524 may transfer by thermal conduction to selected section 526 of formation 516. In addition, generated heat may transfer from a reaction zone to the selected section to a lesser extent by convection heat transfer. Selected section 526, sometimes referred to herein as the "pyrolysis zone," may be substantially adjacent to reaction zone 524. Since oxidation product (and excess oxidation fluid such as air) is typically removed from the reaction zone, the pyrolysis zone can receive heat from the reaction zone without being exposed to oxidation product, or oxidants, that are in the reaction zone.
Oxidation product and/or oxidation fluids may cause the formation of undesirable formation products if they are present in the pyrolysis zone. For example, in certain embodiments it is desirable to conduct pyrolysis in a reducing environment. Thus, it is often useful to allow heat to transfer from the reaction zone to the pyrolysis zone while inhibiting or preventing oxidation product and/or oxidation fluid from reaching the pyrolysis zone.
Pyrolysis of hydrocarbons, or other heat-controlled processes, may.take place in heated selected section 526.
Selected section 526 may be at a temperature between about 270 C to about 400 C for pyrolysis. The temperature of selected section 526 may be increased by heat transfer from reaction zone 524. A rate of temperature increase may be selected as in any of the embodiments described herein. A temperature in formation 516, selected section 526, arid/or reaction zone 524 may be controlled such that production of oxides of nitrogen may be substantially inhibited. Oxides of nitrogen are often produced at temperatures above about 1200 C.

A temperature within opening 514 may be monitored with a thermocouple disposed in opening 514.
Alternatively, a thermocouple may be disposed on conduit 512 and/or disposed on a face of reaction zone 524, and a temperature may be monitored accordingly.
The temperature in the formation may be monitored by the thermocouple, and power input or oxidant introduced into the formation may be controlled based upon the monitored temperature such that the monitored temperature is maintained within a selected range. The selected range may vary, depending on, for example, a desired heating rate of formation 516. In an embodiment, monitored temperature is maintained within a selected range by increasing or decreasing a flow rate of oxidizing fluid 517. For example, if a temperature within opening 514 falls below a selected range of temperatures, the flow rate of oxidizing fluid 517 is increased to increase the combustion and thereby increase the temperature within opening 514.
In certain embodiments one or more natural distributed combustors may be placed along strike and/or horizontally. Doing so tends to reduce pressure differentials along the heated length of the well. The absence of pressure differentials may make controlling the temperature generated along a length of the heater more uniform and more easy to control.

In some embodiments, a presence of air or oxygen (02) in oxidation product 519 may be monitored.

Alternatively, an amount of nitrogen, carbon monoxide, carbon dioxide, oxides of nitrogen, oxides of sulphur, etc. may be monitored in oxidation product 519.
Monitoring the composition and/or quantity of oxidation product 519 may be useful for heat balances, for process diagnostics, process control, etc.
FIG. 11 illustrates an embodiment of a section of overburden with a natural distributed combustor as described in FIG. 10. Overburden casing 541 may be disposed in overburden 540 of formation 516. Overburden casing 541 may be substantially surrounded by materials (e.g., an insulating material such as cement) that may substantially inhibit heating of overburden 540.
Overburden casing 541 may be made of a metal material such as, but not limited to, carbon steel, or 304 stainless steel.

Overburden casing may be placed in reinforcing material 544 in overburden 540. Reinforcing material 544 may be, for example, cement, sand, concrete, etc.

Packing material 542 may be disposed between overburden casing 541 and opening 514 in the formation. Packing material 542 may be any substantially non-porous material (e.g., cement, concrete, grout, etc.). Packing material 542 may inhibit flow of fluid outside of conduit 512 and between opening 514 and surface 550.
Inner conduit 513 may provide a fluid into opening 514 in formation 516. Conduit 512 may remove a combustion product (or excess oxidation fluid) from opening 514 in formation 516. Diameter of conduit 512 may be determined by an amount of the combustion product produced by oxidation in the natural distributed combustor. For example, a larger diameter may be required for a greater amount of exhaust product produced by the natural distributed combustor heater.
In an alternative embodiment, at least a portion of the formation may be heated to a temperature such that at least a portion of the hydrocarbon containing formation may be converted to coke and/or char. Coke and/or char may be formed at temperatures above about 400 C and at a high heating rate (e.g., above about 10 C/day). In the presence of an oxidizing fluid, the coke or char will oxidize. Heat may be generated from the oxidation of coke or char as in any of the embodiments described herein.

FIG. 12 illustrates an embodiment of a natural distributed combustor heater. Insulated conductor 562 may be coupled to conduit 532 and placed in opening 514 in formation 516. Insulated conductor 562 may be disposed internal to conduit 532 (thereby allowing retrieval of the insulated conductor 562), or, alternately, coupled to an external surface of conduit 532. Such insulating material may include, for example, minerals, ceramics, etc. Conduit 532 may have critical flow orifices 515 disposed along its length within opening 514. Critical flow orifices 515 may be configured as described herein. Electrical current may be applied to insulated conductor 562 to generate radiant heat in opening 514. Conduit 532 may be configured to serve as a return for current. Insulated conductor 562 may be configured to heat portion 518 of the formation to a temperature sufficient to support oxidation of hydrocarbons. Portion 518, reaction zone 524, and selected section 526 may have characteristics as described herein. Such a temperature may include temperatures as described herein.

Oxidizing fluid source 508 may provide oxidizing fluid into conduit 532. Oxidizing fluid may be provided into opening 514 through critical flow orifices 515 in conduit 532. Oxidizing fluid may oxidize at least a portion of the hydrocarbon containing formation in reaction zone 524. Reaction zone 524 may have characteristics as described herein. Heat generated at reaction zone 524 may transfer heat to selected section 526, for example, by convection, radiation, and/or conduction. Oxidation product may be removed through a separate conduit placed in opening 514 or through an opening 543 in overburden casing 541. The separate conduit may be configured as described herein.
Packing material 542 and reinforcing material 544 may be configured as described herein.

FIG. 13 illustrates an embodiment of a natural distributed combustor heater with an added fuel conduit.
Fuel conduit 536 may be disposed into opening 514. It may be disposed substantially adjacent to conduit 533 in certain embodiments. Fuel conduit 536 may have critical flow orifices 535 along its length within opening 514.
Conduit 533 may have critical flow orifices 515 along its length within opening 514. Critical flow orifices 515 may be configured as described herein. Critical flow orifices 535 and critical flow orifices 515 may be placed on fuel conduit 536 and conduit 533, respectively, such that a fuel fluid provided through fuel conduit 536 and an oxidizing fluid provided through conduit 533 may not substantially heat fuel conduit 536 and/or conduit 533 upon reaction. For example, the fuel fluid and the oxidizing fluid may react upon contact with each other, thereby producing heat from the reaction. The heat from this reaction may heat fuel conduit 536 and/or conduit 533 to a temperature sufficient to substantially begin melting metallurgical materials in fuel conduit 536 and/or conduit 533 if the reaction takes place proximate to fuel conduit 536 and/or conduit 533. Therefore, a design for disposing critical flow orifices 535 on fuel conduit 536 and critical flow orifices 515 on conduit 533 may be provided such that the fuel fluid and the oxidizing fluid may not substantially react proximate to the conduits. For example, conduits 536 and 533 may be spatially coupled together such that orifices that spiral around the conduits are oriented in opposite directions.
Reaction of the fuel fluid and the oxidizing fluid may produce heat. The fuel fluid may be, for example, natural gas, ethane, hydrogen or synthesis gas that is generated in the in situ process in another part of the formation. The produced heat may be configured to heat portion 518 to a temperature sufficient to support oxidation of hydrocarbons. Upon heating of portion 518 to a temperature sufficient to support oxidation, a flow of fuel fluid into opening 514 may be turned down or may be turned off. Alternatively, the supply of fuel may be continued throughout the heating of the formation, thereby utilizing the stored heat in the carbon to maintain the temperature in opening 514 above the autoignition temperature of the fuel.

The oxidizing fluid may oxidize at least a portion of the hydrocarbons at reaction zone 524. Generated heat will transfer heat to selected section 526, for example, by radiation, convection, and/or conduction. An oxidation product may be removed through a separate conduit placed in opening 514 or through an opening 543 in overburden casing 541.
FIG. 14 illustrates an embodiment of a system configured to heat a hydrocarbon containing formation.
Electric heater 510 may be disposed within opening 514 in hydrocarbon containing formation 516. Opening 514 may be formed through overburden 540 into formation 516.

Opening 514 may be at least about 5 cm in diameter.
Opening 514 may, as an example, have a diameter of about 13 cm. Electric heater 510 may heat at least portion 518 of hydrocarbon containing formation 516 to a temperature sufficient to support oxidation (e.g., about 260 C).

Portion 518 may have a width of about 1 m. An oxidizing fluid (e.g., liquid or gas) may be provided into the opening through conduit 512 or any other appropriate fluid transfer mechanism. Conduit 512 may have critical flow orifices 515 disposed along a length of the conduit.
Critical flow orifices 515 may be configured as described herein.

For example, conduit 512 may be a pipe or tube configured to provide the oxidizing fluid into opening 514 from oxidizing fluid source 508. For example, conduit 512 may be a stainless steel tube. The oxidizing fluid may include air or any other oxygen containing fluid (e.g., hydrogen peroxide, oxides of nitrogen, ozone). Mixtures of oxidizing fluids may be used. An oxidizing fluid mixture may include, for example, a fluid including fifty percent oxygen and fifty percent nitrogen. The oxidizing fluid may also, in some embodiments, include compounds that release oxygen when heated such as hydrogen peroxide. The oxidizing fluid may oxidize at least a portion of the hydrocarbons in the formation.

In some embodiments, a heat exchanger disposed external to the formation may be configured to heat the oxidizing fluid. The heated oxidizing fluid may be provided into the opening from (directly or indirectly) the heat exchanger. For example, the heated oxidizing fluid may be provided from the heat exchanger into the opening through a conduit disposed in the opening and coupled to the heat exchanger. In some embodiments the conduit may be a stainless steel tube. The heated oxidizing fluid may be configured to heat, or at least contribute to the heating of, at least a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons. After the heated portion reaches such a temperature, heating of the oxidizing fluid in the heat exchanger may be reduced or may be turned off.
FIG. 15 illustrates another embodiment of a system configured to heat a hydrocarbon containing formation.
Heat exchanger 520 may be disposed external to opening 514 in hydrocarbon containing formation 516.
Opening 514 may be formed through overburden 540 into formation 516. Heat exchanger 520 may provide heat from another surface process, or it may include a heater (e.g., an electric or combustion heater). Oxidizing fluid source 508 may provide an oxidizing fluid to heat exchanger 520. Heat exchanger 520 may heat an oxidizing fluid (e.g., above 200 C or a temperature sufficient to support oxidation of hydrocarbons). The heated oxidizing fluid may be provided into opening 514 through conduit 521. Conduit 521 may have critical flow orifices 515 disposed along a length of the conduit.

Critical flow orifices 515 may be configured as described herein. The heated oxidizing fluid may heat, or at least contribute to the heating of, at least portion 518 of the formation to a temperature sufficient to support oxidation of hydrocarbons. The oxidizing fluid may oxidize at least a portion of the hydrocarbons in the formation.

In another embodiment, a fuel fluid may be oxidized in a heater located external to a hydrocarbon containing formation. The fuel fluid may be oxidized with an oxidizing fluid in the heater. As an example, the heater may be a flame-ignited heater. A fuel fluid may include any fluid configured to react with oxygen. Fuel fluids may be, but are not limited to, methane, ethane, propane, other hydrocarbons, hydrogen, synthesis gas, or combinations thereof. The oxidized fuel fluid may be provided into the opening from the heater through a conduit and oxidation products and unreacted fuel may return to the surface through another conduit in the overburden. The conduits may be coupled within the overburden. In some embodiments, the conduits may be concentrically placed. The oxidized fuel fluid may be configured to heat, or at least contribute to the heating of, at least a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons. Upon reaching such a temperature, the oxidized fuel fluid may be replaced with an oxidizing fluid. The oxidizing fluid may oxidize at least a portion of the hydrocarbons at a reaction zone within the formation.

An electric heater may be configured to heat a portion of the hydrocarbon containing formation to a temperature sufficient to support oxidation of hydrocarbons. The portion may be proximate to or substantially adjacent to the opening in the formation.
The portion may also radially extend a width of less than approximately 1 m from the opening. A width of the portion may vary, however, depending on, for example, a power supplied to the heater. An oxidizing fluid may be provided to the opening for oxidation of hydrocarbons.
Oxidation of the hydrocarbons may be configured to heat the hydrocarbon containing formation in a process of natural distributed combustion. Electrical current applied to the electric heater may subsequently be reduced or may be turned off. Thus, natural distributed combustion may be configured, in conjunction with an electric heater, to provide a reduced input energy cost method to heat the hydrocarbon containing formation compared to using an electric heater.

An insulated conductor heater may be a heater element of a heat source. In an embodiment of an insulated conductor heater, the insulated conductor heater is a mineral insulated cable or rod. An insulated conductor heater may be placed in an opening in a hydrocarbon containing formation. The insulated conductor heater may be placed in an uncased opening in the hydrocarbon containing formation. Placing the heater in an uncased opening in the hydrocarbon containing formation may allow heat transfer from the heater to the formation by radiation, as well as, conduction. In addition, using an uncased opening may also allow retrieval of the heater from the well, if necessary, and may eliminate the cost of the casing. Alternately, the insulated conductor heater may be placed within a casing in the formation;
may be cemented within the formation; or may be packed in an opening with sand, gravel, or other fill material.
The insulated conductor heater may be supported on a support member positioned within the opening. The support member may be a cable, rod, or a conduit (e.g., a pipe). The support member may be made of a metal, ceramic, inorganic material, or combinations thereof.
Portions of a support member may be exposed to formation fluids and heat during use, so the support member may be chemically resistant and thermally resistant.

Ties, spot welds and/or other types of connectors may be used to couple the insulated conductor heater to the support member at various locations along a length of the insulated conductor heater. The support member may be attached to a wellhead at an upper surface of the formation. In an alternate embodiment of an insulated conductor heater, the insulated conductor heater is designed to have sufficient structural strength so that a support member is not needed. The insulated conductor heater will in many instances have some flexibility to inhibit thermal expansion damage when heated or cooled.
In certain embodiments, insulated conductor heaters may be placed in wellbores without support members and/or centralizers. This can be accomplished for heaters if the insulated conductor has a suitable combination of temperature resistance, length, thickness (diameter) and metallurgy that will inhibit failure of the insulated conductor during use. In an embodiment, insulated conductors that are heated to working temperature of about 700 C are less that about 150 meters in length, and have 3 mm diameter nichrome conductors are used without support members for the insulated conductors.

FIG. 16 depicts a perspective view of an end portion of an embodiment of an insulated conductor heater 562.
An insulated conductor heater may have any desired cross sectional shape, such as, but not limited to round (as shown in FIG. 16), triangular, ellipsoidal, rectangular, hexagonal or irregular shape. An insulated conductor heater may include conductor 575, electrical insulation 576 and sheath 577. The conductor 575 may resistively heat when an electrical current passes through the conductor. An alternating or direct current may be used to heat the conductor 575. In an embodiment, a 60 cycle AC current may be used.
In some embodiments, the electrical insulation 576 may inhibit current leakage and may inhibit arcing to the sheath 577. The electrical insulation 576 may also thermally conduct heat generated in the conductor 575 to the sheath 577. The sheath 577 may radiate or conduct heat to the formation. An insulated conductor heater 562 may be 1000 m or more in length. In an embodiment of an insulated conductor heater, the insulated conductor heater 562 may have a length from about 15 m to about 950 m. Longer or shorter insulated conductors may also be used to meet specific application needs. In embodiments of insulated conductor heaters, purchased insulated conductor heaters have lengths of about 100 m to 500 m (e.g., 230 m). In certain embodiments, dimensions of sheaths and/or conductors of an insulated conductor may be formed so that the insulated conductors have enough strength to be self supporting even at upper working temperatures. Such insulated cables may be suspended rom wellheads or supports positioned near an interface between an overburden and a hydrocarbon containing formation without the need for support members extending into the hydrocarbon formation along with the insulated conductors.

In an embodiment, a higher frequency current may be used to take advantage of the skin effect in certain metals. In some embodiments, a 60 cycle AC current may be used in combination with conductors made of metals that exhibit pronounced skin effects. For example, ferromagnetic metals like iron alloys and nickel may exhibit a skin effect. The skin effect confines the current to a region close to the outer surface of the conductor, thereby effectively increasing the resistance of the conductor. A higher resistance may be desired to decrease the operating current, minimize ohmic losses in surface cables, and also minimize the cost of surface facilities.

As illustrated in FIG. 17, an insulated conductor heater 562 will in many instances be designed to operate at a power level of up to about 1650 watts/meter. The insulated conductor heater 562 may typically operate at a power level between about 500 watts/meter and about 1150 watts/meter when heating a formation. The insulated conductor heater 562 may be designed so that a maximum voltage level at a typical operating temperature does not cause substantial thermal and/or electrical breakdown of electrical insulation 576. The insulated conductor heater 562 may be designed so that the sheath 577 does not exceed a temperature that will result in a significant reduction in corrosion resistance properties of the sheath material.
In an embodiment of an insulated conductor heater 562, the conductor 575 may be designed to reach temperatures within a range between about 650 C to about 870 C, and the sheath 577 may be designed to reach temperatures within a range between about 535 C to about 760 C. Insulated conductors having other operating ranges may be formed to meet specific operational requirements. In an embodiment of an insulated conductor heater 562, the conductor 575 is designed to operate at about 760 C, the sheath 577 is designed to operate at about 650 C, and the insulated conductor heater is designed to dissipate about 820 watts/meter.

An insulated conductor heater 562 may have one or more conductors 575. For example, a single insulated conductor heater may have three conductors within electrical insulation that are surrounded by a sheath.
FIG. 16 depicts an insulated conductor heater 562 having a single conductor 575. The conductor may be made of metal. The material used to form a conductor may be, but is not limited to, nichrome, nickel, and a number of alloys made from copper and nickel in increasing nickel concentrations from pure copper to Alloy 30, Alloy 60, Alloy 180 and Monel. Alloys of copper and nickel may advantageously have better electrical resistance properties than substantially pure nickel or copper.

In an embodiment, the conductor may be chosen to have a diameter and a resistivity at operating temperatures such that its resistance, as derived from Ohm's law, makes it electrically and structurally stable for the chosen power dissipation per meter, the length of the heater, and/or the maximum voltage allowed to pass through the conductor. In an alternate embodiment, the conductor may be designed, using Maxwell's equations, to make use of skin effect heating in and/or on the conductor.

The conductor may be made of different material along a length of the insulated conductor heater. For example, a first section of the conductor may be made of a material that has a significantly lower resistance than a second section of the conductor. The first section may be placed adjacent to a formation layer that does not need to be heated to as high a temperature as a second formation layer that is adjacent to the second section.
The resistivity of various sections of conductor may be adjusted by having a variable diameter and/or by having conductor sections made of different materials.

A diameter of a conductor 575 may Lypically be between about 1.3 mm to about 10.2 mm. Smaller or larger diameters may also be used to have conductors with desired resistivity characteristics. In an embodiment of an insulated conductor heater, the conductor is made of Alloy 60 that has a diameter of about 5.8 mm.

As illustrated in FIG. 16, an electrical insulator 576 of an insulated conductor heater 562 may be made of a variety of materials. Pressure may be used to place electrical insulator powder between a conductor 575 and a sheath 577. Low flow characteristics and other properties of the powder and/or the sheaths and conductors may inhibit the powder from flowing out of the sheaths. Commonly used powders may include, but are not limited to, MgO, A1203, Zirconia, BeO, different chemical variations of Spinels, and combinations thereof. MgO may provide good thermal conductivity and electrical insulation properties. The desired electrical insulation properties include low leakage current and high dielectric strength. A low leakage current decreases the possibility of thermal breakdown and the high dielectric strength decreases the possibility of arcing across the insulator. Thermal breakdown can occur if the leakage current causes a progressive rise in the temperature of the insulator leading also to arcing across the insulator. An amount of impurities 578 in the electrical insulator powder may be tailored to provide required dielectric strength and a low level of leakage current.

The impurities 578 added may be, but are not limited to, CaO, Fe203, A1203, and other metal oxides. Low porosity of the electrical insulation tends to reduce leakage current and increase dielectric strength. Low porosity may be achieved by increased packing of the MgO powder during fabrication or by filling of the pore space in the MgO powder with other granular materials, for example, A1203.

The impurities 578 added to the electrical insulator powder may have particle sizes that are smaller than the particle sizes of the powdered electrical insulator. The small particles may occupy pore space between the larger particles of the electrical insulator so that the porosity of the electrical insulator is reduced.

Examples of powdered electrical insulators that may be used to form electrical insulation 576 are "H" mix manufactured by Idaho Laboratories Corporation (Idaho Falls, Idaho), or Standard MgO used by Pyrotenax Cable Company (Trenton, Ontario) for high temperature applications. In addition, other powdered electrical insulators may be used.
A sheath 577of an insulated conductor heater 562 may be an outer metallic layer. The sheath 577 may be in contact with hot formation fluids. The sheath 577 may need to be made of a material having a high resistance to corrosion at elevated temperatures. Alloys that may be used in a desired operating temperature range of the sheath include, but are not limited to, 304 stainless steel, 310 stainless steel, Incoloy 800, and Inconel 600.
The thickness of the sheath has to be sufficient to last for three to ten years in a hot and corrosive environment. A thickness of the sheath may generally vary between about 1 mm and about 2.5 mm. For example, a 1.3 mm thick 310 stainless steel outer layer provides a sheath 577 that is able to provide good chemical resistance to sulfidation corrosion in a heated zone of a formation for a period of over 3 years. Larger or smaller sheath thicknesses may be used to meet specific application requirements.

An insulated conductor heater may be tested after fabrication. The insulated conductor heater may be required to withstand 2-3 times an operating voltage at a selected operating temperature. Also, selected samples of produced insulated conductor heaters may be required to withstand 1000 VAC at 760 C for one month.
As illustrated in FIG. 17a, a short flexible transition conductor 571 may be connected to a lead-in conductor 572 using a connection 569 made during heater installation in the field. The transition conductor 571 may, for example, be a flexible, low resistivity, stranded copper cable that is surrounded by rubber or polymer insulation. A transition conductor 571 may typically be between about 1.5 m and about 3 m, although longer or shorter transition conductors may be used to accommodate particular needs. Temperature resistant cable may be used as transition conductor 571. The transition conductor 571 may also be connected to a short length of an insulated conductor heater that is less resistive than a primary heating section of the insulated conductor heater. The less resistive portion of the insulated conductor heater may be referred to as a"cold pin" 568.

A cold pin 568 may be designed to dissipate about one tenth to about one fifth of the power per unit length as is dissipated in a unit length of the primary heating section. Cold pins may typically be between about 1.5 m to about 15 m, although shorter or longer lengths may be used to accommodate specific application needs. In an embodiment, the conductor of a cold pin section is copper with a diameter of about 6.9 mm and a length of 9.1 m.
The electrical insulation is the same type of insulation used in the primary heating section. A sheath of the cold pin may be made of Inconel 600. Chloride corrosion cracking in the cold pin region may occur, so a chloride corrosion resistant metal such as Inconel 600 may be used as the sheath.

As illustrated in FIG. 17a, a small, epoxy filled canister 573 may be used to create a connection between a transition conductor 571 and a cold pin 568. Cold pins 568 may be connected to the primary heating sections of insulated conductor 562 heaters by "splices" 567. The length of the cold pin 568 may be sufficient to significantly reduce a temperature of the insulated conductor heater 562. The heater sectiori of the insulated conductor heater 562 may operate from about 530 C to about 760 C, the splice 567 may be at a temperature from about 260 C to about 370 C, and the temperature at the lead-in cable connection to the cold pin may be from about 40 C to about 90 C. In addition to a cold pin at a top end of the insulated conductor heater, a cold pin may also be placed a-t a bottom end of the insulated conductor heater. The cold pin at the bottom end may in many instances make a bottom termination easier to manufacture.

Splice material may have to withstand a temperature equal to half of a target zone operating temperature.
Density of electrical insulation in the splice should in many-instances be high enough to withstand the required temperature and the operating voltage.

A splice 567 may be required to withstand 1000 VAC at 480 C. Splice material may be high temperature splices made by Idaho Laboratories Corporation or by Pyrotenax Cable Company. A splice may be an internal type of splice or an external splice. An internal splice is typically made without welds on the sheath of the insulated conductor heater. The lack of weld on the sheath may avoid potential weak spots (mechanical and/or electrical) on the insulated cable heater. An external splice is a weld made to couple sheaths of two insulated conductor heaters together. An external splice may need to be leak tested prior to insertion of the insulated cable heater into a formation. Laser welds or orbital TIG (tungsten inert gas) welds may be used to form external splices. An additional strain relief assembly may be placed around an external splice to improve the splice's resistance to'bending and to protect the external splice against partial or total parting.

An insulated conductor assembly may include heating sections, cold pins, splices, and termination canisters and flexible transition conductors. The insulated conductor assembly may need to be examined and electrically tested before installation of the assembly into an opening in a formation. The assembly may need to be examined for competent welds and to make sure that there are no holes in the sheath anywhere along the whole heater (including the heated section, the cold-pins, the splices and the termination cans). Periodic X-ray spot checking of the commercial product may need to be made.
The whole cable may be immersed in water prior to electrical testing. Electrical testing of the assembly may need to show more than 2000 megaohms at 500 VAC at room temperature after water immersion. In addition, the assembly may need to be connected to 1000 VAC and show less than about 10 microamps per meter of resistive leakage current at room temperature. Also, a check on leakage current at about 760 C may neud to show less than about 0.4 milliamps per meter.
There are a number of companies that manufacture insulated conductor heaters. Such manufacturers include, but are not limited to, MI Cable Technologies (Calgary, Alberta), Pyrotenax Cable Company (Trenton, Ontario), Idaho Laboratories Corporation (Idaho Falls, Idaho), and Watlow (St. Louis, MO). As an example, an insulated conductor heater may be ordered from Idaho Laboratories as cable model 355-A90-310-"H" 30'/750'/30' with Inconel..600 sheath for the cold-pins, three phase Y
configuration and bottom jointed conductors. The required specification for the heater should also include 1000 VAC, 1400 F quality cable in addition to the preferred mode specifications described above. The designator 355 specifies the cable OD (0.355"), A90 specifies the conductor material, 310 specifies the heated zone sheath alloy (SS 310), "H" specifies the Mg0 mix, 30'/750'/30' specifies about a 230 m heated zone with cold-pins top and bottom having about 9 m lengths.
A similar part number with the same specification using high temperature Standard purity MgO cable may be ordered from Pyrotenax Cable Company.

One or more insulated conductor heaters may be placed within an opening in a formation to form a heat source or heat sources. Electrical current may be passed through each insulated conductor heater in the opening to heat the formation. Alternately, electrical current may be passed through selected insulated conductor heaters in an opening. The unused conductors may be backup heaters.
Insulated conductor heaters may be electrically coupled to a power source in any convenient manner. Each end of an insulated conductor heater may be coupled to lead-in cables that pass through a wellhead. :uch a configuration typically has a 1800 bend (a "hairpin"
bend) or turn located near a bottom of the heat source.
An insulated conductor heater that includes a 180 bend or turn may not require a bottom termination, but the 180 bend or turn may be an electrical and/or structural weakness in the heater. Insulated conductor heaters may be electrically coupled together in series, in parallel, or in series and parallel combinations. In some embodiments of heat sources, electrical current may pass into the conductor of an insulated conductor heater and may returned through the sheath of the insulated conductor heater by connecting the conductor 575 to the sheath 577 at the bottom of the heat source.

In an embodiment of a heat source depicted in FIG. 17, three insulated conductor heaters 562 are electrically coupled in a 3-phase Y configuration to a power supply. The power supply may provide a 60 cycle AC
current to the electrical conductors. No bottom connection may be required for the insulated conductor heaters. Alternately, all three conductors of the three phase circuit may be connected together near the bottom of a heat source opening. The connection may be made directly at ends of heating sections of the insulated conductor heaters or at ends of cold pins coupled to the heating sections at the bottom of the insulated conductor heaters. The bottom connections may be made with insulator filled and sealed canisters or with epoxy filled canisters. The insulator may be the same composition as the insulator used as the'electrical insulation.

The three insulated conductor heaters depicted in FIG. 17 may be coupled to support member 564 using centralizers 566. Alternatively, the -Lhree insulated conductor heaters may be strapped directly to the support tube using metal straps. Centralizers 566 may be configured to maintain a location of insulated conductor heaters 562 on support member 564. Centralizers 566 may be made of, for example, metal, ceramic or a combination thereof. The metal may be stainless steel or any other type of metal able to withstand a corrosive and hot environment. In some embodiments, centralizers 566 may be simple bowed metal strips welded to the support member at distances less than about 6 meters. A ceramic used in centralizer 566 may be, but is not limited to, A1203, MgO
or other insulator. Centralizers 566 may be configured to maintain a location of insulated conductor heaters 562 on support member 564 such that movement of insulated conductor heaters may be substantially inhibited at operating temperatures of the insulated conductor heaters. Insulated conductor heaters 562 may also be somewhat flexible to withstand expansion of support member 564 during heating. Centralizers 566 may also be configured as described in any of the embodiments herein.
Support member 564, insulated conductor heater 562, and centralizers 566 may be placed in opening 514 in hydrocarbon containing formation 516. Insulated conductor heaters 562 may be coupled to bottom conductor junction 570 using cold pin transition conductor 568.
Bottom conductor junction 570 may electrically couple each insulated conductor heater 562 to each other.

Bottom conductor junction 570 may include materials that are electrically conducting and do not melt at temperatures found in opening 514. Cold pin transition conductor 568 may be an insulated conductor heater having lower electrical resistance than insulated conductor heater 562. As illustrated in FIG. 17u, cold pin 568 may be coupled to transition conductor 571 and insulated conductor heater 562. Cold pin transition conductor 568 may provide a temperature transition between transition conductor 571 and insulated conductor heater 562.
Lead-in conductor 572 may be coupled to welihead 590 to provide electrical power to insulated conductor heater 562. Wellhead 590 may be configured as shown in FIG. 18 and as described in any of the embodiments herein. Lead-in conductor 572 may be made of a relatively low electrical resistance conductor such that relatively little or substantially no heat may be generated from electrical current passing through lead-in conductor 572. For example, the lead-in conductor may include, but may not be limited to, a rubber insulated stranded copper wire, but the lead-in conductor may also be a mineral-insulated conductor with a copper core.
Lead-in conductor 572 may couple to a wellhead 590 at surface 550 through a sealing flange located between overburden 540 and surface 550. The sealing flange 590c may be configured as shown in FIG. 18 and as described in any of the embodiments herein. The sealing flange may substantially inhibit fluid from escaping from opening 514 to surface 550.

Packing material 542 (see FIG. 17) may optionally be placed between overburden casing 541 and opening 514.
Overburden casing 541 may include any materials configured to substantially contain cement 544. In an embodiment of a heater source, overburden casing is a 7.6 cm (3 inch) diameter carbon steel, schedule 40 pipe.
Packing material 542 may be configured to inhibit fluid from flowing from opening 514 to surface 550. Overburden casing 541 may be placed in cement 544 in overburden 540 of formation 516. Cement 544 may include, for example, Class G or Class H Portland cement mixed with silica flour for improved high temperature performance, slag or silica flour, and/or a mixture thereof (e.g., about 1.58 grams per cubic centimetre slag/silica flour). In selected heat source embodiments, cement 544 extends radially a width of from about 5 cm to about 25 cm. In some embodiments cement 544 may extend radially a width of about 10 cm to about 15 cm.'In some other embodiments, cement 544 may be designed to inhibit heat transfer from conductor 564 into formation 540 within the overburden.
In certain embodiments one or more conduits may be provided to supply additional components (e.g., nitrogen, carbon dioxide, reducing agents such as gas containing hydrogen, etc.) to formation openings, to bleed off fluids, and/or to control pressure. Formation pressures tend to be highest near heating sources and thus it is often beneficial to have pressure control equipment proximate the heating source. In some embodiments adding a reducing agent proximate the heating source assists in providing a more favourable pyrolysis environment (e.g., a higher hydrogen partial pressure). Since permeability and porosity tend to increase more quickly proximate the heating source, it is often optimal to add a reducing agent proximate the heating source so that the reducing agent can more easily move into the formation.

In FIG. 17, for example, conduit 5000 may be provided to add gas from gas source 5003, through valve 5001, and into.opening 514 (an opening 5004 is provided in packing material 542 to allow gas to pass into opening 514).
Conduit 5000 and valve 5002 may also be used at different times to bleed off pressure and/or control pressure proximate to opening 514. In FIG. 19, for example, conduit 5010 may be provided to add ga; from gas source 5013,through valve 5011, and into opening 514 (an opening is provided in cement 544 to allow gas to pass into opening 514). Conduit 5010 and valve 5012 may also be used at different times to bleed off pressure and/or control pressure proximate to opening 514. It is to be understood that any of the heating sources described herein may also be equipped with conduits to supply additional components, bleed off fluids, and/or to control pressure.
Supp.ort member 564 and lead-in conductor 572 may be coupled to wellhead 59.0 at surface 550 of formation 516.
Surface conductor 545 may enclose cement 544 and may couple to wellhead 590. Embodiments of heater source surface conductor 545 may have a diameter of about 10.16 cm to about 30.48 cm or, for example, a diameter of about 22 cm. Embodiments of surface casings may extend to depths of approximately 3m to approximately 515 m into an opening in the formation. Alternatively, the surface casing may extend to a depth of approximately 9 m into the opening. Electrical current may be supplied from a power source to insulated conductor heater 562 to generate heat due to the electrical resistance of conductor 575 as illustrated in FIG. 16. As an example, a voltage of about 330 volts and a current of about 266 amps are supplied to insulated conductors 562 to generate a heat of about 1150 watts/meter in insulated conductor heater 562. Heat generated from the three insul-ated conductor heaters 562 may transfer (e.g., by radiation) within opening 514 to heat at least a portion of the formation 516.

An appropriate configuration of an insulated conductor heater may be determined by optimizing a material cost of the heater based on a length of heater, a power required per meter of conductor, and a desired operating voltage. In addition, an operating current and voltage may be chosen to optimize the cost of input electrical energy in conjunction with a material cost of the insulated conductor heaters. For example, as input electrical energy increases, the cost of materials needed to withstand the higher voltage may also increase. The insulated conductor heaters may be configured to generate a radiant heat of approximately 650 watts/meter of conductor to approximately 1650 watts/meter of conductor.
The insulated conductor heater may operate at a temperature between approximately 530 C and approximately 760 C within a formation.

Heat generated by an insulated conductor heater may heat at least a portion of a hydrocarbon containing formation. In some embodiments heat may be transferred to the formation substantially by radiation of the generated heat to the formation. Some heat may be transferred by conduction or convection of heat due to gases present in the opening. The opening may be an uncased opening. An uncased opening eliminates cost associated with thermally cementing the heater to the formation, costs associated with a casing, and/or costs of packing a heater within an opening. In addition, the heat transfer by radiation is generally more efficient than by conduction so the heaters will operate at lower temperatures in an open wellbore. The conductive heat trans-fer may be enhanced by the addition of a gas in the opening at pressures up to about 27 bar absolute. The gas may include, but may not be limited to, carbon dioxide and/or helium. Still another advantage is that the heating assembly will be free to undergo thermal expansion. Yet another advantage is tl.at the heaters may be replaceable.

The insulated conductor heater, as described in any of the embodiments herein, may be installed in opening 514 by any method known in the art. In an embodiment, more than one spooling assembly may be used to install both the electric heater and a support member simultaneously. U.S. Patent No. 4,572,299 issued to Van Egmond et al., which is incorporated by reference as if fully set forth herein, describes spooling an electric heater into a well. Alternatively, the support member may be installed using a coiled tubing unit including any unit known in the art. The heaters may be un-spooled and connected to the support as the support is inserted into the well. The electric heater and the support member may be un-spooled from the spooling assemblies. Spacers may be coupled to the support member and the heater along a length of the support member. Additional spooling assemblies may be used for additional electric heater elements.

In an embodiment, the support member may be installed using standard oil field operations and welding different sections of support. Welding may be done by using orbital welding. For example, a first section of the support member may be disposed into the well. A second section (e.g., of substantially similar length) may be coupled to the first section in the well. The second section may be coupled by welding the second section to the first section. An orbital welder disposed at the wellhead may be'configured to weld the second section to the first section. This process may be repeated with subsequent sections coupled to previous sections until a support of desired length is within the well.

FIG. 18 illustrates a cross-sectional view of one embodiment of a wellhead coupled, e.g., to overburden casing 541. Flange 590c may be coupled to, or may be a part of, wellhead 590. Flange 590c may be, for example, carbon steel, stainless steel or any other commercially available suitable sealing material. Flange 590c may be sealed with o-ring 590f, or any other sealing mechanism.
Thermocouples 590g may be provided into wellhead 590 through flange 590c. Thermocouples 590g may measure a temperature on or proximate to support member 564 within the heated portion of the well. Support member 564 may be coupled to flange 590c. Support member 564 may be configured to support one or more insulated conductor heaters as described herein. Support member 564 may be sealed in flange 590c by welds 590h. Alternately, support member 564 may be sealed by any method known in the art.

Power conductor 590a may be coupled to a lead-in cable and/or an insulated conductor heater. Power conductor 590a may be configured to provide electrical energy to the insulated conductor heater. Power conductor 590a may be sealed in sealing flange 590d.
Sealing flange 590d may be sealed by compression seals or o-rings 590e. Power conductor 590a may be coupled to support member 564 with band 590i. Band 590i may include a rigid and corrosion resistant material such as stainless steel. Wellhead 590 may be sealed with weld 590h such that fluid may be substantially inhibited from-escaping the formation through wellhead 590. Lift bolt 590j may be configured to lift wellhead 590 and support member 564. Wellhead 590 may also include a pressure control valve. Compression fittings 590k may serve to seal power cable 590a and compression fittings 5901 may serve to seal thermououple 590g. These seals inhibit fluids from escaping the formation. The pressure control valve may be configured to control a pressure within an opening in which support member 564 may be disposed.

In an embodiment, a control system may be configured to control electrical power supplied to an insulated conductor heater. Power supplied to the insulated conductor heater may be controlled with any appropriate type of controller. For alternating current, the controller may, for example, be a tapped transformer.
Alternatively, the controller may be a zero crossover electrical heater firing SCR (silicon controlled rectifier) controller. Zero crossover electrical heater firing control may be achieved by allowing full supply voltage to the insulated conductor heater to pass through the insulated conductor heater for a specific number of cycles, starting at the "crossover," where an instantaneous voltage may be zero, continuing for a specific number of complete cycles, and discontinuing when the instantaneous voltage again may cross zero. A
specific number of cycles may be blocked, allowing control of the heat output by the insulated conductor heater. For example, the control system may be arranged to block fifteen and/or twenty cycles out of each sixty cycles that may be supplied by a standard 60 Hz alternating current power supply. Zero crossover firing control may be advantageously used with materials having a low temperature coefficient materials. Zero crossover firing control may substantially inhibit current spikes from occurring in an insulated conductor heater.

FIG. 19 illustrates an embodiment of a conductor-in-conduit heater configured to heat a section of a hydrocarbon containing formation. Conuuctor 580 may be disposed in conduit 582. Conductor 580 may be a rod or conduit of electrically conductive material. A
conductor 580 may have a low resistance section 584 at both the top and the bottom of the conductor 580 in order to generate less heating in these sections 584. The substantially low resistance section 584 may be due to a greater cross-sectional area of conductor 580 in that section. For example, conductor 580 may be a 304 or 310 stainless steel rod with a diameter of approximately 2.8 cm. - The diameter and wall thickness of conductor 580 may vary, however, depending on, for example, a desired heating rate of the hydrocarbon containing formation.
Conduit 582 may include an electrically conductive material. For example, conduit 582 may be a 304 or 310 stainless steel pipe having a diameter of approximately 7.6 cm and a thickness of approximately schedule 40.
Conduit 582 may be disposed in opening 514 in formation 516. Opening 514 may have a diameter of at least approximately 5 cm. The diameter of the opening may vary, however, depending on, for example, a desired heating rate in the formation and/or a diameter of conduit 582. For example, a diameter of the opening may be from about 10 cm to about 13 cm. Larger diameter openings may also be used. For example, a larger opening may be used if more than one conductor is to be placed within a conduit.

Conductor 580 may be centred in conduit 582 through centralizer 581. Centralizer 581 may electrically isolate conductor 580 from conduit 582. In addition, centralizer 581 may be configured to locate conductor 580 within conduit 582. Centralizer 581 may be made of a ceramic material or a combination of ccramic and metallic materials. More than one centralizer 581 may be configured to substantially inhibit deformation of conductor 580 in conduit 582 during use. More than one centralizer 581 may be spaced at intervals between approximately 0.5 m and approximately 3 m along conductor 580. Centralizer 581 may be made of ceramic, 304 stainless steel, 310 stainless steel, or other types of metal. Centralizer 581 may be configured as shown in FIG. 22 and/or FIGs. 23a and 23b.

As depicted in FIG. 20, sliding connector 583 may couple an end of conductor 580 disposed proximate a lowermost surface of conduit 582. Sliding connector 583 allows for differential thermal expansion between conductor 580 and conduit 582. Sliding connector 583 is attached to a conductor 580 located at the bottom of the well at a low resistance section 584 which may have a greater cross-sectional area. The lower resistance of section 584 allows the sliding connector to operate at temperatures no greater than about 90 C. In this manner, corrosion of the sliding connector components is minimized and therefore contact resistance between sliding connector 583 and conduit 582 is also minimized.
Sliding connector 583 may be configured as shown in FIG. 20 and as described in any of the embodiments herein. The substantially low resistance section 584 of the conductor 580 may couple conductor 580 to wellhead 690 as depicted in FIG. 19. Wellhead 690 may be configured as shown in FIG. 21 and as described in any of the embodiments herein. Electrical current may be applied to conductor 580 from power cable 585 through a low resistance section 584 of the conductor 580.
Electrical current may pass from conductor 580 through sliding connector 583 to conduit 582. Conduit 582 may be electrically insulated from overburden casing 541 and from wellhead 690 to return electrical current to power cable 585. Heat may be generated in conductor 580 and conduit 582. The generated heat may radiate within conduit 582 and opening 514 to heat at least a portion of formation 516. As an example, a voltage of about 330 volts and a current of about 795 amps may be supplied to conductor 580 and conduit 582 in a 229 m (750 ft) heated section to generate about 1150 watts/meter of conductor 580 and conduit 582.

Overburden conduit 541 may be disposed in overburden 540 of formation 516. Overburden conduit 541 may in some embodiments be surrounded by materials that may substantially inhibit heating of overburden 540. A
substantially low resistance section 584 of a conductor 580 may be placed in overburden conduit 541.
The substantially low resistance section 584 of conductor 580 may be made of, for example, carbon steel.
The substantially low resistance section 584 may have a diameter between about 2 cm to about 5 cm or, for example, a diameter of about 4 cm. A substantially low resistance section 584 of conductor 580 may be centralized within overburden conduit 541 using centralizers 581. Centralizers 581 may be spaced at intervals of approximately 6 m to approximately 12 m or, for example, approximately 9 m along substantially low resistance section 584 of conductor 580. A substantially low resistance section 584 of conductor 580 may be coupled to conductor 580 using any method known in the art such as arc welding. A substantially low resistance section 584 may be configured to generate little and/or substantially no heat in overburden conduit 541. Packing material 542 may be placed between ovei-burden casing 541 and opening 514. Packing material 542 may be configured to substantially inhibit fluid from flowing from opening 514 to surface 550 or to inhibit most heat carrying fluids from flowing from opening 514 to surface 550.

Overburden conduit may include, for example, a conduit of carbon steel having a diameter of about 7.6 cm arid a thickness of about schedule 40 pipe. Cement 544 may include, for example, slag or silica flour, or a mixture thereof (e.g., about 1.58 grams per cubic centimetre slag/silica flour). Cement 544 may extend radially a width of about 5 cm to about 25 cm.
Cement 544 may also be made of material designed to inhibit flow of heat into formation 516.
Surface conductor 545 and overburden casing 541 may enclose cement 544 and may couple to welihead 690.
Surface conductor 545 may have a diameter of about 10 cm to about 30 cm and more preferably a diameter of about 22 cm. Electrically insulating sealing flanges may be configured to mechanically couple substantially low resistance section 584 of conductor 580 to wellhead 690 and to electrically couple lower resistance section 584 to power cable 585. The electrically insulating sealing flanges may be configured to couple lead-in conductor 585 to wellhead 690. For example, lead-in conductor 585 may include a copper cable, wire, or other elongated member.
Lead-in conductor 585 may include, however, any material having a substantially low resistance. The lead-in conductor may be clamped to the bottom of the low resistivity conductor to make electrical contact.

In an embodiment, heat may be generated in or by conduit 582. In this manner, about 10 % to about 30 or, for example, about 20 %, of the tot-al heat generated by the heater may be generated in or by conduit 582.
Both conductor 580 and conduit 582 may be made of stainless steel. Dimensions of conductor 580 and conduit 582 may be chosen such that the conductor will dissipate heat in a range from approximately 650 watts per meter to 1650 watts per meter. A temperature in conduit 582 may be approximately 480 C to approximately 815 C and a temperature in conductor 580 may be approximately 500 C to 840 C. Substantially uniform heating of a hydrocarbon containing formation may be provided along a length of conduit 582 greater than about 300 m or, maybe, greater than about 600 m. A
length of conduit 582 may vary, however, depending on, for example, a type of hydrocarbon containing formation, a depth of an opening in the formation, and/or a length of the formation desired for treating.

The generated heat may be configured to heat at least a portion of a hydrocarbon containing formation. Heating of at least the portion may occur substantially by radiation of the generated heat within an opening in the formation and to a lesser extent by gas conduction. In this manner, a cost associated with filling the opening with a filling material to provide conductive heat transfer between the insulated conductor and the formation may be eliminated. In addition, heat transfer by radiation is generally more efficient than by conduction so the heaters will generally operate at lower tempe'ratures in an open wellbore. Still another advantage is that the heating assembly will be free to undergo thermal expansion. Yet another advantage is that the heater may be replaceable.

The conductor-in-conduit heater, as described in any of the embodiments herein, may be instdlled in opening 514. In an embodiment, the conductor-in-conduit heater may be installed into a well by sections. For example, a first section of the conductor-in-conduit heater may be disposed into the well. The section may be about 12 m in length. A second section (e.g., of substantially similar length) may be coupled to the first section in the well. The second section may be coupled by welding the second section to the first section and/or with threads disposed on the first and second section.
An orbital welder disposed at the wellhead may be configured to weld the second section to the first section. This process may be repeated with subsequent sections coupled to previous sections until a heater of desired length may be disposed in the well. In some embodiments, three sections may be coupled prior to being disposed in the well. The three sections may be coupled by welding. The three sections may have a length of about 12.2 m each. The resulting 37 m section may be lifted vertically by a crane at the wellhead. The three sections may be coupled to three additional sections in the well as described herein. Welding the three sections prior to being disposed in the well may reduce a number of leaks and/or faulty welds and may decrease a time required for installation of the heater.

In an alternate embodiment, the conductor-in-conduit heater may be spooled onto a spooling assembly. The spooling assembly may be mounted on a transportable structure. The transportable structure may be transported to a well location. The conductor-in-conduit heater may be un-spooled from the spooling assembly into the well.

FIG. 20 illustrates an embodiment of a sliding connector. Sliding connector 583 may include scraper 593 that may abut an inner surface of conduit 582 at point 595. Scraper 593 may include any metal or electrically conducting material (e.g., steel or stainless steel). Centralizer 591 may couple to conductor 580. In some embodiments, conductor 580 may have a substantially low resistance section 584, due to an increased thickness, substantially around a location of sliding connector 583. Centralizer 591 may include any electrically conducting material (e.g., a metal or metal alloy). Centralizer 591 may be coupled to scraper 593 through spring bow 592. Spring bow 592 may include any metal or electrically conducting material (e.g., copper-beryllium alloy). Centralizer 591, spring bow 592, and/or scraper 593 may be coupled through any welding method known in the art. Sliding connector 583 may electrically couple the substantially low resistance section 584 of conductor 580 to conduit 582 through centralizer 591, spring bow 592, and/or scraper 593.

During heating of conductor 580, conductor 580 may expand at a substantially different rate than conduit 582. For example, point 594 on conductor 580 may move relative to point 595 on conduit 582 during heating of conductor 580.
Scraper 593 may maintain electrical contact with conduit 582 by sliding along surface of conduit 582.
Several sliding connectors may be used for redundancy and to reduce the current at each scraper. In addition, a thickness of conduit 582 may be increased for a length substantially adjacent to sliding connector 583 to substantially reduce heat generated in that portion of the conduit 582. The length of conduit 582 with increased thickness may be, for example, approximately 6 m.

FIG. 21 illustrates another embodiment of a wellhead.
Wellhead 690 may be coupled to electrical junction box 690a by flange 690n or any other suitable mechanical device. Electrical junction box 690a may be configured to control power (current and voltage) supplied to an electric heater. The electric heater may be a conductor-in-conduit heater as described herein. Flange 690n may include, for example, stainless steel or any other suitable sealing material. Conductor 690b may be disposed in flange 690n and may electrically couple overburden casing 541 to electrical junction box 690a.
Conductor 690b may include any metal or electrically conductive material (e.g., copper). Compression seal 690c may seal conductor 690b at an inner surface of electrical junction box 690a.

Flange 690n may be sealed with metal o-ring 690d.
Conduit 690f, which may be, e.g., a pipe, may couple flange 690n to flange 690m. Flange 690m may couple to overburden casing 541. Flange 690m may be sealed with o-ring 690g (e.g., metal o-ring or steel o-ring). The substantially low resistance section 584 of the conductor (e.g., conductor 580) may couple to electrical junction box 690a. The substantially low resistance section 584 may be passed through flange 690n and may be sealed in flange 690n with o-ring assembly 690p. Assemblies 690p are designed to insulate the substantially low resistance section 584 of conductor 580 from flange 690n and flange 690m. 0-ring assembly 690c may be designed to electrically insulate conductor 690b from flange 690m and junction box 690a. Centralizer 581 may couple to low resistance section 584. Electrically insulating centralizer 581 may have characteristics as described in any of the embodiments herein. Thermocouples 690i may be coupled to thermocouple flange 690q with connectors 690h and wire 690j. Thermocouples 690i may be enclosed in an electrically insulated sheath (e.g., a metal sheath).

Thermocouples 690i may be sealed in thermocouple flange 690q with compression seals 690k. Thermocouples 690i may be used to monitor temperatures in the heated portion downhole.

FIG. 22 illustrates a perspective view of an embodiment of a centralizer in, e.g., conduit 582.
Electrical insulator 581a may be disposed on conductor 580. Insulator 581a may be made of, for example, aluminum oxide or any other electrically insulating material that may be configured for use at high temperatures. A location of insulator 581a on the conductor 580 may be maintained by disc 581d. Disc 581d may be welded to conductor 580. Spring bow 581c may be coupled to insulator 581a by disc 581b. Spring bow 581c and disc 581b may be made of metals such as 310 stainless steel and any other thermally conducting material that may be configured for use at high temperatures.
Centralizer 581 may be arranged as a single cylindrical member disposed on conductor 580. Centralizer 581 may be arranged as two half-cylindrical members disposed on conductor 580. The two half-cylindrical members may be coupled to conductor 580 by band 581e. Band 581e may be made of any material configured for use at high temperatures (e.g., steel).

FIG. 23a illustrates a cross-sectional view of an embodiment of a centralizer 58le disposed on conductor 580. FIG. 23b illustrates a perspective view of the embodiment shown in FIG. 23a. Centralizer 581e may be made of any suitable electrically insulating material that may substantially withstand high voltage at high temperatures. Examples of such materials may be aluminum oxide and/or Macor. Discs 581d may maintain positions of centralizer 581e relative to conductor 580.

Discs 581d may be metal discs welded to conductor 580.
Discs 581d may be tack-welded to conductor 580.
Centralizer 581e may substantially electrically insulate conductor 580 from conduit 582.

In an embodiment, a conduit may be pressurized with a fluid to balance a pressure in the conduit with a pressure in an opening. In this manner, deformation of the conduit may be substantially inhibited. A thermally conductive fluid may be configured to pressurize the conduit. The thermally conductive fluid may increase heat transfer within the conduit. The thermally conductive fluid may include a gas such as helium, nitrogen, air, or mixtures thereof. A pressurized fluid may also be configured to pressurize the conduit such that the pressurized fluid may inhibit arcing between the conductor and the conduit. If air and/or air mixtures are used to pressurize the conduit, the air and/or air mixtures may react with materials of the conductor and the conduit to form an oxide on a surface of the conductor and the conduit such that the conductor and the conduit are at least somewhat more resistant to corrosion.

An emissivity of a conductor and/or a conduit may be increased. For example, a surface of the conductor and/or the conduit may be roughened to increase the emissivity. Blackening the surface of the conductor and/or the conduit may also increase the emissivity.
Alternatively, oxidation of the conductor and/or the conduit prior to installation may be configured to increase the emissivity. The conductor and/or the conduit may also be oxidized by heating the conductor and/or the conduit in the presence of an oxidizing fluid in the conduit and/or in an opening in a hydrocarbon containing formation. Another alternative for increasing the emissivity may be to anodize the conductor and/or the conduit such that the surface may be roughened and/or blackened.
In another embodiment, a perforated tube may be placed in the opening formed in the hydrocarbon containing formation proximate to and external the first conduit. The perforated tube may be configured to remove fluids formed in the opening. In this manner, a pressure may be maintained in the opening such that deformation of the first conduit may be substantially inhibited and the pressure in the formation near the heaters may be reduced. The perforated tube may also be used to increase or decrease pressure in the formation by addition or removal of a fluid or fluids from the formation. This may allow control of the pressure in the formation and control of quality of produced hydrocarbons. Perforated tubes may be used for pressure control in all described embodiments of heat sources using an open hole configuration. The perforated tube may also be configured to inject gases to upgrade hydrocarbon properties in situ; for example, hydrogen gas may be injected under elevated pressure.

FIG. 24 illustrates an alternative embodiment of a conductor-in-conduit heater configured to heat a section of a hydrocarbon containing formation. Second conductor 586 may be disposed in conduit 582 in addition to conductor 580. Conductor 580 may be configured as described herein. Second conductor 586 may be coupled to conductor 580 using connector 587 located near a lowermost surface of conduit 582. Second conductor 586 may be configured as a return path for the electrical current supplied to conductor 580. For example, second conductor 586 may return electrical current to wellhead 690 through second substantially low resistance conductor 588 in overburden casing 541. Second conductor 586 and conductor 580 may be configured of an elongated conductive material. Second conductor 586 and conductor 580 may be, for example, a stainless steel rod having a diameter of approximately 2.4 cm. Connector 587 may be flexible. Conduit 582 may be electrically isolated from conductor 580 and second conductor 586 using centralizers 581. Overburden casing 541, cement 544, surface conductor 545, and packing material 542 may be configured as described in the embodiment shown in FIG. 19. Advantages of this embodiment include the absence of a sliding contactor, which may extend the life of the heater, and the isolation of all applied power from formation 516.

In another embodiment, a second conductor may be disposed in a second conduit, and a third conductor may be disposed in a third conduit. The second opening may be different from the opening for the first conduit. The third opening may be different from the opening for the first conduit and the second opening. For example, each of the first, second, and third openings may be disposed in substantially different well locations of the formation and may have substantially similar dimensions.
The first, second, and third conductors may be configured as described herein. The first, second, and third conductors may be electrically coupled in a 3-phase Y
electrical configuration. The outer conduits may be connected together or may be connected to the ground.
The 3-phase Y electrical configuration may provide a safer, more efficient method to heat a hydrocarbon containing formation than using a single conductor. The first, second, and/or third conduits may be electrically isolated from the first, second, and third conductors, respectively. Dimensions of each conductor and each conduit may be configured such that each conductor may generate heat of approximately 650 watts per meter of conductor to approximately 1650 watts per meter of conductor. In an embodiment, a first conductor and a second conductor in a conduit may be coupled by a flexible connecting cable. The bottom of the first and second conductor may be enlarged to create low resistance sections, and thus generate less heat. In this manner, the flexible connector may be made of, for example, stranded copper covered with rubber insulation.
In an embodiment, a first conductor and a second conductor may be coupled to at least one sliding connector within a conduit. The sliding connector may be configured as described herein. For example, such a sliding connector may be configured to generate less heat than the first conductor or the second conductor. The conduit may be electrically isolated from the first conductor, second conductor, and/or the sliding connector. The sliding connector may be placed in a location within the first conduit where substantially less heating of the hydrocarbon containing formation may be required.

In an embodiment, a thickness of a section of a conduit may be increased such that substantially less heat may be transferred (e.g., radiated) along the section of increased thickness. The section with increased thickness may preferably be formed along a length of the conduit where less heating of the hydrocarbon containing formation may be required.
In an embodiment, the conductor may be formed of sections of various metals that are welded together. The cross sectional area of the various metals may be selected to allow the resulting conductor to be long, to be creep resistant at high operating temperatures, and/or to dissipate substantially the same amount of heat per unit length along the entire length of the conductor.
For example, a first section may be made of a creep resistant metal (such as, but not limited to, Inconel 617 or HR120) and a second section of the conductor may be made of 304 stainless steel. The creep resistant first section may help to support the second section. The cross sectional area of the first section may be larger than the cross sectional area of the second section. The larger cross sectional area of the first section may allow for greater strength of the first section. Higher resistivity properties of the first section may allow the first section to dissipate the same amount of heat per unit length as the smaller cross sectional area second section.

In some embodiments, the cross sectional area and/or the metal used for a particular section may be chosen so that a particular section provides greater (or lesser) heat dissipation per unit length than an adjacent section. More heat may be provided near an interface between a hydrocarbon layer and a non-hydrocarbon layer (e.g., the overburden and the hydrocarbon containing formation) to counteract end effects and allow for more uniform heat dissipation into the hydrocarbon containing formation. A higher heat dissipation may also be located at a lower end of an elongated member to counteract end effects and allow for more uniform heat dissipation.

In an embodiment, an elongated member may be disposed within an opening (e.g., an open wellbore) in a hydrocarbon containing formation. The opening may preferably be an uncased opening in the hydrocarbon containing formation. The opening may have a diameter of at least approximately 5 cm or, for example, approximately 8 cm. The diameter of the opening may vary, however, depending on, for example, a desired heating rate in the formation. The elongated member may be a length (e.g., a strip) of metal or any other elongated piece of metal (e.g., a rod). The elongated member may include stainless steel. The elongated member, however, may also include any conductive material configurable to generate heat to sufficiently heat a portion of the formation and to substantially withstand a corresponding temperature within the opening, for example, it may be configured to withstand corrosion at the temperature within the opening.

An elongated member may be a bare metal heater.
"Bare metal" refers to a metal that does not include a layer of electrical insulation, such as mineral insulation, that is designed to provide electrical insulation for the metal throughout an operating temperature range of the elongated member. Bare metal may encompass a metal that includes a corrosion inhibiter such as a naturally occurring oxidation layer, an applied oxidation layer, and/or a film. Bare metal includes metal with polymeric or other types of electrical insulation that cannot retain electrical insulating properties at typical operating temperature of the elongated member. Such material may be placed on the metal and may be thermally degraded during use of the heater.

An elongated member may have a length of about 650 meters. Longer lengths may be achieved using sections of high strength alloys, but such elongated members may be expensive. In some embodiments, an elongated member may be supported by a plate in a wellhead. The elongated member may include sections of different conductive materials that are welded together end-to-end. A large amount of electrically conductive weld material may be used to couple the separate sections together to increase strength of the resulting member and to provide a path for electricity to flow that will not result in arcing and/or corrosion at the welded connections. The different conductive materials may include alloys with a high creep resistance. The sections of different conductive materials may have varying diameters to ensure uniform heating along the elongated member. A first metal that has a higher creep resistance than a second metal typically has a higher resistivity than the second metal. The difference in resistivities may allow a section of larger cross sectional area, more creep resistant first metal to dissipate the same amount of heat as a section of smaller cross sectional area second metal. The cross sectional areas of the two different metals may be tailored to result in substantially the same amount of heat dissipation in two welded together sections of the metals. The conductive materials may include, but are not limited to, 617 Inconel, HR-120, 316 stair''-ss steel, ~
and 304 stainless steel. For example, an elongated member may have a 60 meter section of 617 Inconel, 60 meter section of HR-120, and 150 meter section of 304 stainless steel. In addition, the elongated member may have a low resistance section that may run from the wellhead through the overburden. This low resistance section may decrease the heating within the formation from the wellhead through the overburden. The low resistance section may be the result of, for example, choosing a substantially electrically conductive material and/or increasing the cross-sectional area available for electrical conduction.

Alternately, a support member may extend through the overburden, and the bare metal elongated member or members may be coupled to a plate, a centralizer or other type of support member near an interface between the overburden and the hydrocarbon formation. A low resistivity cable, such as a stranded copper cable, may extend along the support member and may be coupled to the elongated member or members. The copper cable may be coupled to a power source that supplies electricity to the elongated member or members.

FIG. 25 illustrates an embodiment of a plurality of elongated members configured to heat a section of a hydrocarbon containing formation. Two or more (e.g., four) elongated members 600 may be supported by support member 604. Elongated members 600 may be coupled to support member 604 using insulated centralizers 602.
Support member 604 may be a tube or conduit. Support member 604 may also be a perforated tube. Support member 604 may be configured to provide a flow of an oxidizing fluid into opening 514. Support member 604 may have a diameter between about 1.2 cm to about 4 cm and more preferably about 2.5 cm. Support member 604, elongated members 600, and insulated centralizers 602 may be disposed in opening 514 in formation 516. Insulated centralizers 602 may be configured to maintain a location of elongated members 600 on support member 604 such that lateral movement of elongated members 600 may be substantially inhibited at temperatures high enough to deform support member 604 or elongated members 600.
Insulated centralizers 602 may be a centralizer as described herein. Elongated members 600, in some embodiments, may be metal strips of about 2.5 cm wide and about 0.3 cm thick stainless steel. Elongated members 600, however, may also include a pipe or a rod formed of a conductive material. Electrical current may be applied to elongated members 600 such that elongated members 600 may generate heat due to electrical resistance.

Elongated members 600 may be configured to generate heat of approximately 650 watts per meter of elongated members 600 to approximately 1650 watts per meter of elongated members 600. In this manner, elongated members 600 may be at a temperature of approximately 480 C to approximately 815 C. Substantially uniform heating of a hydrocarbon containing formation may be provided along a length of elongated members 600 greater than about 305 m or, maybe, greater than about 610 m. A
length of elongated members 600 may vary, however, depending on, for example, a type of hydrocarbon containing formation, a depth of an opening in the formation, and/or a length of the formation desired for treating.

Elongated members 600 may be electrically coupled in series. Electrical current may be supplied to elongated members 600 using lead-in conductor 572. Lead-in conductor 572 may be further configurea as described herein. Lead-in conductor 572 may be coupled to wellhead 690. Electrical current may be returned to wellhead 690 using lead-out conductor 606 coupled to elongated members 600. Lead-in conductor 572 and lead-out conductor 606 may be coupled to wellhead 690 at surface 550 through a sealing flange located between wellhead 690 and overburden 540. The sealing flange may substantially inhibit fluid from escaping from opening 514 to surface 550. Lead-in conductor 572 and lead-out conductor 606 may be coupled to elongated members using a cold pin transition conductor. The cold pin transition conductor may include an insulated conductor of substantially low resistance such that substantially no heat may be generated by the cold pin transition conductor. The cold pin transition conductor may be coupled to lead-in conductor 572, lead-out conductor 606, and/or elongated members 600 by any splicing or welding methods known in the art. The cold pin transition conductor may provide a temperature transition between lead-in conductor 572, lead-out conductor 606, and/or elongated members 600. The cold pin transition conductor may be further configured as described in any of the embodiments herein. Lead-in conductor 572 and lead-out conductor 606 may be made of low resistance conductors such that substantially no heat may be generated from electrical current passing through lead-in conductor 572 and lead-out conductor 606.

Weld beads may be placed beneath the centralizers 602 on the support member 604 to fix the position of the centralizers. Weld beads may be placed on the elongated members 600 above the uppermost centralizer to fix the position of the elongated members relative to the support member (other types of connecting mechanisms may also be used). When heated, the elongated member may thermally expand downwards. The elongated member may be formed of different metals at different locations along a length of the elongated member to allow relatively long lengths to be formed. For example, a "U" shaped elongated member may include a first length formed of 310 stainless steel, a second length formed of 304 stainless steel welded to the first length, and a third length formed of 310 stainless steel welded to the second length.

310 stainless steel is more resistive than 304 stainless steel and may dissipate approximately 25% more energy per unit length than 304 stainless steel of the same dimensions. 310 stainless steel may be more creep resistant than 304 stainless steel. The first length and the third length may be formed with cross sectional areas that allow the first length and third lengths to dissipate as much heat as a smaller cross area section of 304 stainless steel. The first and third lengths may be positioned close to the wellhead 690. The use of different types of metal may allow the formation of long elongated members. The different metals may be, but are not limited to, 617 Inconel, HR120, 316 stainless steel, 310 stainless steel, and 304 stainless steel.

Packing material 542 may be placed between overburden casing 541 and opening 514. Packing material 542 may be configured to inhibit fluid flowing from opening 514 to surface 550 and to inhibit corresponding heat losses towards the surface. Packing material 542 may be further configured as described herein. Overburden casing 541 may be placed in cement 544 in overburden 540 of formation 516. Overburden casing 541 may be further configured as described herein.. Surface conductor 545 may be disposed in cement 544. Surface conductor 545 may be configured as described herein. Support member 604 may be coupled to wellhead 690 at surface 550 of formation 516. Centralizer 581 may be configured to maintain a location of support member 604 within overburden casing 541. Centralizer 581 may be further configured as described herein. Electrical current may be supplied to elongated members 600 to generate heat.
Heat generated from elongated members 600 may radiate within opening 514 to heat at least a portion of formation 516.

The oxidizing fluid may be provided along a length of the elongated members 600 from oxidizing fluid source 508. The oxidizing fluid may inhibit carbon deposition on or proximate to the elongated members. For example, the oxidizing fluid may react with hydrocarbons to form carbon dioxide, which may be removed from the opening. Openings 605 in support member 604 may be configured to provide a flow of the oxidizing fluid along the length of elongated members 600. Openings 605 may be critical flow orifices as configured and described herein. Alternatively, a tube may be disposed proximate to elongated members 600 to control the pressure in the formation as described in above embodiments. In another embodiment, a tube may be disposed proximate to elongated members 600 to provide a flow of oxidizing fluid into opening 514. Also, at least one of elongated members 600 may include a tube having openings configured to provide the flow of oxidizing fluid. Without the flow of oxidizing fluid, carbon deposition may occur on or proximate to elongated members 600 or on insulated centralizers 602, thereby causing shorting between elongated members 600 and insulated centralizers 602 or hot spots along elongated members 600. The oxidizing fluid may be used to react with the carbon in the formation as described herein. The heat generated by reaction with the carbon may complement or supplement the heat generated electrically.

In an embodiment, a plurality of elongated members may be supported on a support member disposed in an opening. The plurality of elongated members may be electrically coupled in either a series or parallel configuration. A current and voltage applied to the plurality of elongated members may be selected such that the cost of the electrical supply of power at the surface in conjunction with the cost of the plurality of elongated members may be minimized. In addition, an operating current and voltage may be chosen to optimize a cost of input electrical energy in conjunction with a material cost of the elongated members. The elongated members may be configured to generate and radiate heat as described herein. The elongated members may be installed in opening 514 as described herein.

In an embodiment, a bare metal elongated member may be formed in a "U" shape (or hairpin) and the member may be suspended from a wellhead or from a positioner placed at or near an interface between the overburden and the formation to be heated. In certain embodiments, the bare metal heaters are formed of rod stock. Cylindrical, high alumina ceramic electrical insulators may be placed over legs of the elongated members. Tack welds along lengths of the legs may fix the position of the insulators. The insulators may inhibit the elongated member from contacting the formation or a well casing (if the elongated member is placed within a well casing). The insulators may also inhibit legs of the "U" shaped members from contacting each other. High alumina ceramic electrical insulators may be purchased from Cooper Industries (Houston, Texas). In an embodiment, the "U"
shaped member may be formed of different metals having different cross sectional areas so that the elongated members may be relatively long and may dissipate substantially the same amount of heat per unit length along the entire length of the elongated member. The use of different welded together sections may result in an elongated member that has large diameter sections near a top of the elongated member and a smaller diameter section or sections lower down a length of the elongated member. For example, an embodiment of an elongated member has two 7/8 inch (2.2 cm) diameter first sections, two 1/2 inch (1.3 cm) middle sections, and a 3/8 inch (0.95 cm) diameter bottom section that is bent into a"U"
shape. The elongated member may be made of materials with other cross section shapes such as ovals, squares, rectangles, triangles, etc. The sections may be formed of alloys that will result in substantially the same heat dissipation per unit length for each section.

In some embodiments, the cross sectional area and/or the metal used for a particular section may be chosen so that a particular section provides greater (or lesser) heat dissipation per unit length than an adjacent section. More heat dissipation per unit length may be provided near an interface between a hydrocarbon layer and a non-hydrocarbon layer (e.g., the overburden and the hydrocarbon containing formation) to counteract end effects and allow for more uniform heat dissipation into the hydrocarbon containing formation. A higher heat dissipation may also be located at a lower end of an elongated member to counteract end effects and allow for more uniform heat dissipation.

FIG. 26 illustrates an embodiment of a surface combustor configured to heat a section of a hydrocarbon containing formation. Fuel fluid 611 may be provided into burner 610 through conduit 617. An oxidizing fluid may be provided into burner 610 from oxidizing fluid source 508. Fuel fluid 611 may be oxidized with the oxidizing fluid in burner 610 to form oxidation products 613. Fuel fluid 611 may include, for example, hydrogen. Fuel fluid 611 may also include methane or any other hydrocarbon fluids. Burner 610 may be located external to formation 516 or within an opening 614 in the hydrocarbon containing formation 516. Flarrie 618 may be configured to heat fuel fluid 611 to a temperature sufficient to support oxidation in burner 610. Flame 618 may be configured to heat fuel fluid 611 to a temperature of about 1425 C. Flame 618 may be coupled to an end of conduit 617. Flame 618 may be a pilot flame. The pilot flame may be configured to burn with a small flow of fuel fluid 611. Flame 618 may, however, be an electrical ignition source.

Oxidation products 613 may be provided into opening 614 within inner conduit 612 coupled to burner 610. Heat may be transferred from oxidation products 613 through outer conduit 615 into opening 614 and to formation 516 along a length of inner conduit 612.
Therefore, oxidation products 613 may substantially cool along the length of inner conduit 612. For example, oxidation products 613 may have a temperature of about 870 C proximate top of inner conduit 612 and a temperature of about 650 C proximate bottom of inner conduit 612. A section of inner conduit 612 proximate to burner 610 may have ceramic insulator 612b disposed on an inner surface of inner conduit 612. Ceramic insulator 612b may be configured to substantially inhibit melting of inner conduit 612 and/or insulation 612a proximate to burner 610. Opening 614 may extend into the formation a length up to about 550 m below surface 550.
Inner conduit 612 may be configured to provide oxidation products 613 into outer conduit 615 proximate a bottom of opening 614. Inner conduit 612 may have insulation 612a. FIG. 27 illustrates an embodiment of inner conduit 612 with insulation 612a and ceramic insulator 612b disposed on an inner surface of inner conduit 612. Insulation 612a may be-configured to substantially inhibit heat transfer between fluids in inner conduit 612 and fluids in outer conduit 615. A

thickness of insulation 612a may be varied along a length of inner conduit 612 such that heat transfer to formation 516 may vary along the length of inner conduit 612. For example, a thickness of insulation 612a may be tapered to from a larger thickness to a lesser thickness from a top portion to a bottom portion, respectively, of inner conduit 612 in opening 614. Such a tapered thickness may provide substantially more uniform heating of formation 516 along the length of inner conduit 612 in opening 614. Insulation 612a may include ceramic and metal materials. Oxidation products 613 may return to surface 550 through outer conduit 615. Outer conduit may have insulation 615a as depicted in FIG. 26. Insulation 615a may be configured to substantially inhibit heat transfer from outer conduit 615 to overburden 540.

Oxidation products 613 may be provided to an additional burner through conduit.619 at surface 550.
Oxidation products 613 may be configured as a portion of a fuel fluid in the additional burner. Doing so may increase an efficiency of energy output versus energy input for heating formation 516. The additional burner may be configured to provide heat through an additional opening in formation 516.

In some embodiments, an electric heater may be configured to provide heat in addition to heat provided from a surface combustor. The electric heater may be, for example, an insulated conductor heater or a conductor-in-conduit heater as described in any of the above embodiments. The electric heater may.be configured to provide the additional heat to a hydrocarbon containing formation such that the hydrocarbon containing formation may be heated substantially uniformly along a depth of an opening in the formation.

Flameless combustors such as those described in U.S.
Patent Nos. 5,255,742 to Mikus et al., 5,404,952 to Vinegar et al., 5,862,858 to Wellington et al., and 5,899,269 to Wellington et al., which are incorporated by reference as if fully set forth herein, may be configured to heat a hydrocarbon containing formation.

FIG. 28 illustrates an embodiment of a flameless combustor configured to heat a section of the hydrocarbon containing formation. The flameless combustor may include centre tube 637 disposed within inner conduit 638. Centre tube 637 and inner conduit 638 may be placed within outer conduit 636. Outer conduit 636 may be disposed within opening 514 in formation 516.

Fuelfluid 621 may be provided into the flameless combustor through centre tube 637. Fuel fluid 621 may include any of the fuel fluids described herein. If a hydrocarbon fuel such as methane is utilized, it may be mixed with steam to prevent coking in centre tube 637.
If hydrogen is used as the fuel, no steam may be required.

Centre tube 637 may include flow mechanisms 635 (e.g., flow orifices) disposed within an oxidation region to allow a flow of fuel fluid 621 into inner conduit 638.
Flow mechanisms 635 may control a flow of fuel fluid 621 into inner conduit 638 such that the flow of fuel fluid 621 is not dependent on a pressure in inner conduit 638. Flow mechanisms 635 may have characteristics as described herein. Oxidizing fluid 623 may be provided into the combustor through inner conduit 638. Oxidizing fluid 623 may be provided from oxidizing fluid source 508. Oxidizing fluid 623 may include any of the oxidizing fluids as described in above embodiments. Flow mechanisms 635 on centre tube 637 may be configured to inhibit flow of oxidizing fluid 623 into centre tube 637.

Oxidizing fluid 621 may mix with fuel fluid 621 in the oxidation region of inner conduit 638. Either oxidizing fluid 623 or fuel fluid 621, or a combination of both, may be preheated external to the combustor to a temperature sufficient to support oxidation of fuel fluid 621. Oxidation of fuel fluid 621 may provide heat generation within outer conduit 636. The generated heat may provide heat to at least a portion of a hydrocarbon containing formation proximate to the oxidation region of inner conduit 638. Products 625 from oxidation of fuel fluid 621 may be removed through outer conduit 636 outside inner conduit 638. Heat exchange between the downgoing oxidizing fluid and the upgoing combustion products in the overburden results in enhanced thermal efficiency. A flow of removed combustion products 625 may be balanced with a flow of fuel fluid 621 and oxidizing fluid 623 to maintain a temperature above autoignition temperature but below a temperature sufficient to produce substantial oxides of nitrogen.
Also, a constant flow of fluids may provide a substantially uniform temperature distribution within the oxidation region of inner conduit 638. Outer conduit 636 may be, for example, a stainless steel tube. In this manner, heating of at least the portion of the hydrocarbon containing formation may be substantially uniform. As described above, the lower operating temperature may also provide a less expensive metallurgical cost associated with the heating system.
Certain heat source embodiments may include an operating system that is coupled to any of heat sources such by insulated conductors or other types of wiring.

The operating system may be configured to interface with the heat source. The operating system may receive a signal (e.g., an electromagnetic signal) from a heater that is representative of a temperature distribution of the heat source. Additionally, the operating system may be further configured to control the heat source, either locally or remotely. For example, the operating system may alter a temperature of the heat source by altering a parameter of equipment coupled to the heat source.
Therefore, the operating system may monitor, alter, and/or control the heating of at least a portion of the formation.

In some embodiments, a heat source as described above may be configured to substantially operate without a control and/or operating system. The heat source may be configured to oilly require a power supply from a power source such as an electric transformer. For example, a conductor-in-conduit heater and/or an elongated member heater may include conductive materials that may be have a thermal property that self-controls a heat output of the heat source. In this manner, the conductor-in-conduit heater and/or the elongated member heater may be configured to operate throughout a temperature range without external control. A conductive material such as stainless steel may be used in the heat sources.
Stainless steel may have a resistivity that increases with temperature, thus, providing a greater heat output at higher temperatures.
Leakage current of any of the heat sources described herein may be monitored. For example, an increase in leakage current may show deterioration in an insulated conductor heater. Voltage breakdown in the insulated conductor heater may cause failure of the heat source.
Furthermore, a current and voltage applied to any of the heat sources may also be monitored. The current and voltage may be monitored to assess/indicate resistance in a heat source. The resistance in the heat source may be configured to represent a temperature in the heat source since the resistance of the heat source may be known as a function of temperature. Another alternative method may include monitoring a temperature of a heat source with at least one thermocouple placed in or proximate to the heat source. In some embodiments, a control system may monitor a parameter of the heat source. The control system may alter parameters of the heat source such that the heat source may provide a desired output such as heating rate and/or temperature increase.

In some embodiments, a thermowell may be disposed into an opening in a hydrocarbon containing formation that includes a heat source. The thermowell may be disposed in an opening that may or may not have a casing.
In the opening without a casing, the thermowell may include appropriate metallurgy and thickness such that corrosion of the thermowell is substantially inhibited.
A thermowell and temperature logging process, such as that described in U.S. Patent No. 4,616,705 issued to Stegemeier et al,, which is incorporated by reference as if fully set forth herein, may be used to monitor temperature. Only selected wells may be equipped with thermowells to avoid expenses associated with installing and operating temperature monitors at each heat source.
In some embodiments, a heat source may be turned down and/or off after an average temperature in a formation may have reached a selected temperature. Turning down and/or off the heat source may reduce input energy costs, substantially inhibit overheating of the formation, and allow heat to substantially transfer into colder regions of the formation.

Certain embodiments include providing heat to a first portion of a hydrocarbon containing formation from one or more heat sources. In addition, certain embodiments may include producing formation fluids from the first portion, and maintaining a second portion of the formation in a substantially unheated condition. The second portion may be substantially adjacent to the first portion of the formation. In this manner, the second portion may provide structural strength to the formation.
Furthermore, heat may also be provided to a third portion of the formation. The third portion may be substantially adjacent to the second portion and/or laterally spaced from the first portion. In addition, formation fluids may be produced from the third portion of the formation.
In this manner, a processed formation may have a pattern that may resemble, for example, a striped or checkerboard pattern with'alternating heated and unheated portions.

Additional portions of the formation may also include such alternating heated and unheated portions. In this manner, such patterned heating of a hydrocarbon containing formation may maintain structural strength within the formation. Maintaining structural strength within a hydrocarbon containing formation may substantially inhibit subsidence. Subsidence of a portion of the formation being processed may decrease a permeability of the processed portion due to.compaction.
In addition, subsidence may decrease the flow of fluids in the formation, which may result in a lower production of formation fluids.

A pyrolysis temperature range may depend on specific types of hydrocarbons within the formation. A pyrolysis temperature range may include temperatures, for example, between approximately 250 C and about 900 C.

Alternatively, a pyrolysis temperature range may include temperatures between about 250 C to about 400 C. For example, a majority of formation fluids may be produced within a pyrolysis temperature range from about 250 C to about 400 C. If a hydrocarbon containing formation is heated throughout the entire pyrolysis range, the formation may produce only small amounts of hydrogen towards the upper limit of the pyrolysis range. After all of the available hydrogen has been depleted, little fluid production from the formation would occur.

Temperature (and average temperatures) within a heated hydrocarbon containing formation may vary, depending on, for example, proximity to a heat source, thermal conductivity and thermal diffusivity of the formation, type of reaction occurring, type of hydrocarbon containing formation, and the presence of water within the hydrocarbon containing formation. A
temperature within the hydrocarbon containing formation may be assessed using a numerical simulation model. The numerical simulation model may assess and/or calculate a subsurface temperature distribution. In addition, the numerical simulation model may include assessing various properties of a subsurface formation under the assessed temperature distribution.

For example, the various properties of the subsurface formation may include, but are not limited to, thermal conductivity of the subsurface portion of the formation and permeability of the subsurface portion of the formation. The numerical simulation model may also include assessing various properties of a fluid formed within a subsurface formation under the assessed temperature distribution. For example, the various properties of a formed fluid may include, but are not limited to, a cumulative volume of a fluid formed at a subsurface of the formation, fluid viscosity, fluid density, and a composition of the fluid formed at a subsurface of the formation. Such a simulation may be used to assess the performance of commercial-scale operation of a small-scale field experiment as described herein. For example, a performance of a commercial-scale development may be assessed based on, but not limited to, a total volume of product that may be produced from a commercial-scale operation.

In some embodiments, an in situ conversion process may increase a temperature or average teniperature within a hydrocarbon containing formation. A temperature or average temperature increase (AT) in a specified volume (V) of the hydrocarbon containing formation may be assessed for a given heat input rate (q) over time (t) by the following equation:

oT= E (gt) C V * p B * V

In this equation, an average heat capacity of the formation (Cv) and an average bulk density of the formation (PB) may be estimated or determined using one or more samples taken from the hydrocarbon containing formation.

In alternate embodiments, an in situ conversion process may include heating a specified volume to a pyrolysis temperature or average pyrolysis temperature.
Heat input rate (q) during a time (t) required to heat the specified volume (V) to a~desired temperature increase (AT) may be determined or assessed using the following equation: Y_ q * t = AT * CV * pB * V. In this equation, an average heat capacity of the formation (Cv) and an average bulk density of the formation (PB) may be estimated or determined using one or more samples taken from the hydrocarbon containing formation.

It is to be understood that the above equations can be used to assess or estimate temperatures, average temperatures (e.g., over selected sections of the formation), heat input, etc. Such equations do not take into account other factors (such as heat losses) which would also have some effect on heating and temperatures asses-sments. However such factors can ordinarily be addressed with correction factors, 'as is commonly done in the art.

In some embodiments, a portion of a hydrocarbon containing formation may be heated at a heating rate in a range from about 0.1 C/day to about 50 C/day.
Alternatively, a portion of a hydrocarbon containing formation may be heated at a heating rate in a range of about 0.1 C/day to about 10 C/day. For example, a majority of hydrocarbons may be produced from a formation at a heating rate within a range of about 0.1 C/day to about 10 C/day. In addition, a hydrocarbon containing formation may be heated at a rate of less than about 0.7 C/day through a significant portion of a pyrolysis temperature range. The pyrolysis temperature range may include a range of temperatures as described in above embodiments. For example, the heated portion may be heated at such a rate for a time greater than 50% of the time needed to span the temperature range, more than 75%
of the time needed to span the temperature range, or more than 90% of the time needed to span the temperature range.
A rate at which a hydrocarbon containing formation is heated may affect the quantity and quality of the formation fluids produced from the hydrocarbon containing formation. For example, heating at high heating rates, as is the case when a Fischer Assay is conducted, may produce a larger quantity of condensable hydrocarbons from a hydrocarbon containing formation. The products of such a process, however, may be of a significantly lower quality than when heating using heating rates less than about 10 C/day. Heating at a rate of temperature increase less than approximately 10 C/day may allow pyrolysis to occur within a pyrolysis temperature range in which production of undesirable products and tars may be reduced. In addition, a rate of temperature increase of less than about 3 C/day may further increase the quality of the produced condensable hydrocarbons by further reducing the production of undesirable products and further reducing production of tars within a hydrocarbon containing formation.

In some embodiments, controlling temperature within a hydrocarbon containing formation may involve controlling a heating rate within the formation. For example, controlling the heating rate such that the heating rate may be less than approximately 3 C/day may provide better control of a temperature within the hydrocarbon containing formation.

An in situ process for hydrocarbons may include monitoring a rate of temperature increase at a production well. A temperature within a portion of a hydrocarbon containing formation, however, may be measured at various locations within the portion of the hydrocarbon containing formation. For example, an in situ process may include monitoring a temperature of the portion at a midpoint between two adjacent heat sources. The temperature may be monitored over time. In this manner, a rate of temperature increase may also be monitored. A
rate of temperature increase may affect a composition of formation fluids produced from the formation. As such, a rate of temperature increase may be monitored, altered and/or controlled, for example, to alter a composition of formation fluids produced from the formation.

In some embodiments, a power (Pwr) required to generate a heating rate (h) in a selected volume (V) of a hydrocarbon containing formation may be determined by the following equation: Pwr=h*V*CV*p. In this equation, an average heat capacity of the hydrocarbon containing formation may be described as CV. The average heat capacity of the hydrocarbon containing formation may be a relatively constant value. Average heat capacity may be estimated or determined using one or more samples taken -from a hydrocarbon containing formation, or measured in situ using a thermal pulse test. Methods of determining average heat capacity based on a thermal pulse test are described by I. Berchenko, E. Detournay, N. Chandler, J.
Martino, and E. Kozak, "In-situ measurement of some thermoporoelastic parameters of a granite" in Poromechanics, A Tribute to Maurice A. Biot, pages 545-550, Rotterdam, 1998 (Balkema), which is incorporated by reference as if fully set forth herein.

In addition, an average bulk density of the hydrocarbon containing formation may be described as p.
The average bulk density of the hydrocarbon containing formation may be a relatively constant value. Average bulk density may be estimated or determined using one or more samples taken from a hydrocarbon containing formation. In certain embodiments the product of average heat capacity and average bulk density of the hydrocarbon containing formation may be a relatively constant value (such product can be assessed in situ using a thermal pulse test). A determined power may be used to determine heat provided from a heat source into the selected volume such that the selected volume may be heated at a heating rate, h. For example, a heating rate may be less than about 3 C/day, and even less than about 2 C/day. In this manner, a heating rate within a range of heating rates may be maintained within the selected volume. It is to be understood that in this context "power" is used to describe energy input per time. The form of such energy input may, however, vary as described herein (i.e., energy may be provided from electrical resistance heaters, combustion heaters, etc.).

The heating rate may be selected based on a number of factors including, but not limited to, the maximum temperature possible at the well, a predetermined quality of formation fluids that may be produced from the formation, etc. A quality of hydrocarbon fluids may be defined by an API gravity of condensable hydrocarbons, by olefin content, by the nitrogen, sulphur and/or oxygen content, etc. In an embodiment, heat may be provided to at least a portion of a hydrocarbon containing formation to produce formation fluids having an API gravity of greater than about 20 . The API gravity may vary, however, depending on, for example, the heating rate and a pressure within the portion of the formation.

In some embodiments, subsurface pressure in a hydrocarbon containing formation may correspond to the fluid pressure generated within the formation. Heating hydrocarbons within a hydrocarbon containing formation may generate fluids, for example, by pyrolysis. The generated fluids may be vaporized within the formation.
Fluids that contribute to the increase in pressure may include, but are not limited to, fluids produced during pyrolysis and water vaporized during heating. The produced pyrolysis fluids may include, but are not limited to, hydrocarbons, water, oxides of carbon, ammonia, molecular nitrogen, and molecular hydrogen.
Therefore, as temperatures within a selected section of a heated portion of the formation increase, a pressure within the selected section may increase as a result of increased fluid generation and vaporization of water.

I-n some embodiments; pressure within a selected section of a heated portion of a hydrocarbon containing formation may vary depending on, for example, depth, distance from a heat source, a richness of the hydrocarbons within the hydrocarbon containing formation, and/or a distance from a producer well. Pressure within a formation may be determined at a number of different locations, which may include but may not be limited to, at a welihead and at varying depths within a wellbore.
In some embodiments, pressure may be measured at a producer well. In alternate embodiments, pressure may be measured at a heater well.

Heating of a hydrocarbon containing formation to a pyrolysis temperature range may occur before substantial permeability has been generated within the hydrocarbon containing formation. An initial lack of permeability may prevent the transport of generated fluids from a pyrolysis zone within the formation. In this manner, as heat is initially transferred from a heat source to a hydrocarbon containing formation, a fluid pressure within the hydrocarbon containing formation may increase proximate to a heat source. Such an increase in fluid pressure may be caused by, for example, generation of fluids during pyrolysis of at least some hydrocarbons in the formation. The increased fluid pressure may be released, monitored, altered, and/or controlled through such a heat source. For example, the heat source may include a valve as described in above embodiments. Such a valve may be configured to control a flow rate of fluids out of and into the heat source. In addition, the heat source may include an open hole configuration through which pressure may be released.

Alternatively, pressure generated by expansion of pyrolysis fluids or other fluids gene'rated in the formation may be allowed to increase although an open path to the production well or any other pressure sink may not yet exist in the formation. In addition, a fluid pressure may be allowed to increase to a lithostatic pressure. Fractures in the hydrocarbon containing formation may form when the fluid pressure equals or exceeds the lithostatic pressure. For example, fractures may form from a heat source to a production well. The generation of fractures within the heated portion may reduce pressure within the portion due to the production of formation fluids through a production well. To maintain a selected pressure within the heated portion, a back pressure may be maintained at the production well.
Fluid pressure within a hydrocarbon containing formation may vary depending upon, for example, thermal expansion of hydrocarbons, generation of pyrolysis fluids, and withdrawal of generated fluids from the formation. For example, as fluids are generated within the formation a fluid pressure within the pores may increase. Removal of generated fluids from the formation may decrease a fluid pressure within the formation.

In an embodiment, a pressure may be increased within a selected section of a portion of a hydrocarbon containing formation to a selected pressure during pyrolysis. A selected pressure may be within a range from about 2 bars absolute to about 72 bars absolute or, in some embodiments, 2 bars absolute to 36 bars absolute.
Alternatively, a selected pressure may be within a range from about 2 bars absolute to about 18 bars absolute.
For example, in certain embodiments, a majority of hydrocarbon fluids may be produced from a formation having a pressure within a range from about 2 bars absolute to about 18 bars absolute. The pressure during pyrolysis may vary or be varied. The pressure may be varied to alter and/or control a composition of a formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid, and/or to control an API gravity of fluid being produced.
For example, decreasing pressure may result in production of a larger condensable fluid component, and the fluid may contain a larger percentage of olefins, and vice versa.

In certain embodiments, pressure within a portion of a hydrocarbon containing formation will increase due to fluid generation within the heated portion. In addition, such increased pressure may be maintained within the heated portion of the formation. For example, increased pressure within the formation may be maintained by bleeding off a generated formation fluid through heat sources and/or by controlling the amount of formation fluid produced from the formation through production wells. Maintaining increased pressure within a formation inhibits formation subsidence. In addition, maintaining increased pressure within a formation tends to reduce the required sizes of collection conduits that are used to transport condensable hydrocarbons. Furthermore, maintaining increased pressure within the heated portion may reduce and/or substantially eliminate the need to compress formation fluids at the surface because the formation products will usually be produced at higher pressure. Maintaining increased pressure within a formation may also facilitate generation of electricity from produced non-condensable fluid. For example, the produced non-condensable fluid may be passed through a turbine to generate electricity.

Increased pressure in the formation may also be maintained to produce more and/or improved formation fluids. In certain embodiments, significant amounts (e.g., a majority) of the formation fluids produced from a formation within the pyrolysis pressure range may include non-condensable hydrocarbons. Pressure may be selectively increased and/or maintained within the formation, and formation fluids can be produced at or near such increased and/or maintained pressures. As pressure within a formation is increased, formation fluids produced from the formation will, in many instances, include a larger portion of non-condensable hydrocarbons. In this manner, a significant amount (e.g., a- majority) of the formation fluids produced at such a pressure may include a lighter and higher quality condensable hydrocarbons than formation fluids produced at a lower pressure.

In addition, a pressure may be maintained within a heated portion of a hydrocarbon containing formation to substantially inhibit production of formation fluids having carbon numbers greater than, for example, about 25. For example, increasing a pressure within the portion of the hydrocarbon containing formation may increase a boiling point of a fluid within the portion.
Such an increase in the boiling point of a fluid may substantially inhibit production of formation fluids having relatively high carbon numbers, and/or production of multi-ring hydrocarbon compounds, because such formation fluids tend to remain in the formation as liquids until they crack.

In addition, increasing a pressure within a portion of a hydrocarbon containing formation may result in an increase in API gravity of formation fluids produced from the formation. Higher pressures may increase production of shorter chain hydrocarbon fluids, which may have higher API gravity values.

In an embodiment, a pressure within a heated portion of the formation may surprisingly increase the quality of relatively high quality pyrolyzation fluids, the quantity of relatively high quality pyrolyzation fluids, and/or vapour phase transport of the pyrolyzation fluids within the formation. Increasing the pressure often permits production of lower molecular weight hydrocarbons since such lower molecular weight hydrocarbons will more readily transport in the vapour phase in the formation.
Generation of lower molecular weight hydrocarbons (and corresponding increased vapour phase transport) is believed to be due, in part, to autogenous generation and reaction of hydrogen within a portion of the hydrocarbon containing formation. For example, maintaining an increased pressure may force hydrogen generated in the heated portion into a liquid phase (e.g. by dissolving).
In addition, heating the portion to a temperature within a pyrolysis temperature range may pyrolyze at least some of the hydrocarbons within the formation to generate pyrolyzation fluids in the liquid phase. The generated components may include a double bond and/or a radical.
H2 in the liquid phase may reduce the double bond of the generated pyrolyzation fluids, thereby reducing a potential for polymerization of the generated pyrolyzation fluids. In addition, hydrogen may also neutralize radicals in the generated pyrolyzation fluids.

There-fore, H2 in the liquid phase may substantially inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation. In this manner, shorter chain hydrocarbons may enter the vapour phase and may be produced from the formation.

Increasing the formation pressure to increase the amount of pyrolyzation fluids in the vapour phase may significantly reduce the potential for coking within the selected section of the formation. A coking reaction may occur in the liquid phase. Since many of the generated components may be transformed into short chain hydrocarbons and may enter the vapour phase, coking within the selected section may decrease.

Increasing the formation pressure to increase the amount of pyrolyzation fluids in the vapour phase is also beneficial because doing so permits increased recovery of lighter (and relatively high quality) pyrolyzation fluids. In general, pyrolyzation fluids are more quickly produced, with less residuals, when such fluids are in the vapour phase rather than in the liquid phase.
Undesirable polymerization reactions also tend to occur more frequently when the pyrolyzation fluids are in the liquid phase instead of the vapour phase. In addition, when pyrolyzation fluids are produced in the vapour phase, fewer production wells/area are needed, thereby reducing project costs.

In an embodiment, a portion of a hydrocarbon containing formation may be heated to increase a partial pressure of H2. In some embodiments, an increased H2 partial pressure may include H2 partial pressures in a range from about 1 bar absolute to about 7 bars absolute.

Alternatively, an increased H2 partial pressure range may include H2 partial pressures in a range from about 5 bars absolute to about 7 bars absolute. For example, a majority of hydrocarbon fluids may be produced within a range of about 5 bars absolute to about 7 bars absolute.
A range of H2 partial pressures within the pyrolysis H2 partial pressure range may vary, however, depending on, for example, a temperature and a pressure of the heated portion of the formation.

Maintaining a H2 partial pressure within the formation of greater than atmospheric pressure may increase an API value of produced condensable hydrocarbon fluids. For example, maintaining such a H2 partial pressure may increase an API value of produced condensable hydrocarbon fluids to greater than about 25 or, in some instances, greater than about 30.
Maintaining such a H2 partial pressure within a heated portion of a hydrocarbon containing formation may increase a concentration of H2 within the heated portion such that H2 may be available to react with pyrolyzed components of the hydrocarbons. Reaction of H2 with the pyrolyzed components of hydrocarbons may reduce polymerization of olefins into tars and other cross-linked, difficult to upgrade, products. Such products may have lower API gravity values. Therefore, production of hydrocarbon fluids having low API gravity values may be substantially inhibited.

A valve may be configured to maintain, alter, and/or control a pressure within a heated portion of a hydrocarbon containing formation. For example, a heat source disposed within a hydrocarbon containing formation may be coupled to a valve. The valve may be configured to release fluid from the formation through the heater source. In addition, a pressure valve may be coupled to a production well, which may be disposed within the hydrocarbon containing formation. In some embodiments, fluids released by the valves may be cullected and transported to a surface unit for further processing and/or treatment.

An in situ conversion process for hydrocarbons may include providing heat to a portion of a hydrocarbon containing formation, and controlling a temperature, rate of temperature increase, and/or a pressure within the heated portion. For example, a pressure within the heated portion may be controlled using pressure valves disposed within a heater well or a production well as described herein. A temperature and/or a rate of temperature increase of the heated portion may be controlled, for example, by altering an amount of energy supplied to one or more heat sources.

Controlling a pressure and a temperature within a hydrocarbon containing formation will, in most instances, affect properties of the produced formation fluids. For example, a composition or a quality of formation fluids produced from the formation may be altered by altering an average pressure and/or an average temperature in the selected section of the heated portion. The quality of the produced fluids may be defined by a property which may include, but may not be limited to, API gravity, percent olefins in the produced formation fluids, ethene to ethane ratio, atomic hydrogen to carbon ratio, percent of hydrocarbons within produced formation fluids having carbon numbers greater than 25, total equivalent production (gas and liquid), total liquids production, and/or liquid yield as a percent of Fischer Assay. For example, controlling the quality of the produced formation fluids may include controlling average pressure and average temperature in the selected section such that the average assessed pressure in the selected section may be greater than the pressure (p) as set forth in the form of the following relationship for an assessed average temperature (T) in the selected section:

I T + BJ
p = expl where p is measured in psia (pounds per square inch absolute), T is measured in degrees Kelvin, A and B are parameters dependent on the value of the selected property. An assessed average temperature may be determined as described herein.

The relationship given above may be rewritten such that the natural log of pressure may be a liriear function of an inverse of temperature. This form of the relationship may be rewritten: ln(p) = A/T +B. In a plot of the absolute pressure as a function of the reciprocal of the absolute temperature, A is the slope and B is the intercept. The intercept B is defined to be the natural logarithm of the pressure as the reciprocal of the temperature approaches zero. Therefore, the slope and intercept values (A and B) of the pressure-temperature relationship may be determined from two pressure-temperature data points for a given value of a selected property. The pressure-temperature data points may include an average pressure within a formation and an average temperature within the formation at which the particular value of the property was, or may be, produced from the formation. For example, the pressure-temperature data points may be obtained from an experiment such as a laboratory experiment or a field experiment.

A relationship between the slope parameter, A, and a value of a property of formation fluids may be determined. For example, values of A may be plotted as a function of values of a formation fluid property. A
cubic polynomial may be fitted to these data. For example, a cubic polynomial relationship such as A = al*(property)3 + a2*(property)2 + a3*(property) + a4 may be fitted to the data, where al, a2, a3, and a4 are empirical constants that may describe a relationship between the first parameter, A, and a property of a formation fluid. Alternatively, relationships having other functional forms such as another order polynomial or a logarithmic function may be fitted to the data. In this manner, al, a2, ..., may be estimated from the results of the data fitting. Similarly, a relationship between the second parameter, B, and a value of a property of formation fluids may be determined. For example, values of B may be plotted as a function of values of a property of a formation fluid. A cubic polynomial may also be fitted to the data. For example, a cubic polynomial relationship such as B= bl* (property) 3+ b2* (property) 2+ b3*(property) + b4 may be fitted to the data, where bl, b2, b3, and b4 are empirical constants that may describe a relationship between the parameter B, and the value of a property of a formation fluid. As such, b1, b2, b3, and b4 may be estimated from results of fitting the data. For example, TABLES la and lb list estimated empirical constants determined for several properties of a formation fluid for Green River oil shale as described above.

TABLE la PROPERTY Al A2 a3 a4 API Gravity -0.738549 -8.893902 4752.182 -145484.6 Ethene/Ethane -15543409 3261335 -303588.8 -2767.469 Ratio Weight 0.1621956 -8.85952 547.9571 -24684.9 Percent of Hydrocarbons Having a Carbon Number Greater Than Atomic H/C 2950062 -16982456 32584767 -20846821 Ratio Liquid 119.2978 -5972.91 96989 -524689 Production (gal/ton) Equivalent -6.24976 212.9383 -777.217 -39353.47 Liquid Production (gal/ton) % Fischer 0.5026013 -126.592 9813.139 -252736 Assay TABLE lb PROPERTY b1 b2 b3 B4 API Gravity 0.003843 -0.279424 3.391071 96.67251 Ethene/Etha- -8974.317 2593.058 -40.78874 23.31395 ne Ratio Weight -0.0005022 0.026258 -1.12695 44.49521 Percent of Hydrocarbons Having a Carbon Number Greater Than Atomic H/C 790.0532 -4199.454 7328.572 -4156.599 Ratio Liquid -0.17808 8.914098 -144.999 793.2477 Production (gal/ton) Equivalent -0.03387 2.778804 -72.6457 650.7211 Liquid Production (gal/ton) % Fischer -0.0007901 0.196296 -15.1369 395.3574 Assay To determine an average pressure and an average temperature that may be used to produce a formation fluid having a selected property, the value of the selected property and the empirical constants as described above 5 may be used to determine values for the first parameter A, and the second parameter B, according to the following relationships:

A = al*(property)3 + a2*(property)2 + a3*(property) + a4 B = bl*(property)3 + b2*(property)2 + b3*(property) + b4 For example, TABLES 2a-2g list estimated values for the parameter A, and approximate valueL3 for the parameter B, as determined for a selected property of a formation fluid as described above.

TABLE 2a API Gravity A B

20 degrees -59906.9 83.46594 25 degrees 43778.5 66.85148 30 degrees -30864.5 50.67593 35 degrees -21718.5 37.82131 40 degrees -16894.7 31.16965 45 degrees -16946.8 33.60297 TABLE 2b Ethene/Ethane Ratio A B
0.20 -57379 83.145 0.10 -16056 27.652 0.05 -11736 21.986 0.01 -5492.8 14.234 TABLE 2c Weight Percent of A B
Hydrocarbons Having a Carbon Number Greater Than 25 25% -14206 25.123 20% -15972 28.442 15% -17912 31.804 10% -19929 35.349 5% -21956 38.849 1% -24146 43.394 TABLE 2d Atomic H/C Ratio A B
1.7 -38360 60.531 1.8 -12635 23.989 1.9. -7953.1 17.889 2.0 -6613.1 16.364 TABLE 2e Liquid Production A B
(gal/ton) 14 gal/ton -10179 21.780 16 gal/ton -13285 25.866 18 gal/ton -18364 32.882 20 gal/ton -19689 34.282 TABLE 2f Equivalent Liquid A B
Production (gal/ton) 20 gal/ton -19721 38.338 25 gal/ton -23350 42.052 30 gal/ton -39768.9 57.68 TABLE 2g % Fischer Assay A B
60% -11118 23.156 70% -13726 26.635 80% -20543 36.191 90% -28554 47.084 The determined values for the parameter A, and the parameter B, may be used to determine an average pressure in the selected section of the formation using an assessed average temperature, T, in the selected section.
The assessed average temperature may be determined as described herein. For example, an average pressure of the selected section may be determined by the relationship: p = exp[(A/T) + B], in which p is measured in psia, and T is measured in degrees Kelvin.

Alternatively, an average absolute pressure of the selected section, measured in bars, may be determined using the following relationship:

pbars = exp[(A/T) + B - 2.6744]. In this manner, an average pressure within the selected section may be controlled such that an average pressure within the selected section is adjusted to the average pressure as determined above, in order to produce a formation fluid from the selected section having a selected property.
Alternatively, the determined values for the parameter A, and the parameter B, may be used to determine an average temperature in the selected section of the formation using an assessed average pressure, P.
in the selected section. The assessed average pressure may be determined as described herein. Therefore, using the relationship described above, an average temperature within the selected section may be controlled to approximate the calculated average temperature in order to produce hydrocarbon fluids having a selected property.
As described herein, a composition of formation fluids produced from a formation may be varied by altering at least one operating condition of an in situ conversion proce.ss for hydrocarbons. In addition, at least one operating condition may be determined by using a computer-implemented method. For example, an.operating condition may include, but is not limited to, a pressure in the formation, a temperature in the formation, a heating rate of the formation, a power supplied to a heat source, and/or a flow rate of a synthesis gas generating fluid. The computer-implemented method may include measuring at least one property of the formation. For example, measured properties may include a thickness of a layer containing hydrocarbons, vitrinite reflectance, hydrogen content, oxygen content, moisture content, depth/width of the hydrocarbon containing formation, and other properties otherwise described herein.

At least one measured property may be inputted into a computer executable program. The program may be operable to determine at least one operating condition from a measured property. In addition, at least one property of selected formation fluids may be input into the program.
For example, properties of selected formation fluids may include, but are not limited to, API gravity, olefin content, carbon number distribution, ethene to ethane ratio, and atomic carbon to hydrogen ratio. The program may also be operable to determine at least one operating condition from a property of the selected formation fluids. In this manner, an operating condition of an in situ conversion process may be altered to be approximate at least one determined operating condition such that production of selected formation fluids from the formation may increase.

In an embodiment, a computer-implemented method may be used to determine at least one property of a formation fluid that may be produced from a hydrocarbon containing formation for a set of operating conditions as a function of time. The method may include measuring at least one property of the formation and providing at least the one measured property to a computer program as described herein. In addition, one or more sets of operating conditions may also be provided to the computer program.
At least one of the operating conditions may include, for example, a heating rate or a pressure. One or more sets of operating conditions may include currently used operating conditions (in an in situ conversion process) or operating conditions being considered for an in situ conversion process. The computer program may be operable to determine at least one property of a formation fluid that may be produced by an in situ conversion process for hydrocarbons as a function of time using at least one set of operating conditions and at least one measured property of the formation. Furthermore, the method may include comparing a determined property of the fluid to a selected property. In this manner, if multiple determined properties are generated by the computer program, then the determined property that differs least from a selected property may be determined.
Formation fluid properties may vary depending on a location of a production well in the formation. For example, a location of a production well with respect to a location of a heat source in the formation may affect the composition of formation fluid produced from a formation. In addition, a distance between a production well and a heat source in a formation may be varied to alter the composition of formation fluid produced from a formation. Decreasing a distance between a production well and a heat source may increase a temperature at the production well. In this manner, a substantial portion of pyrolyzation fluids flowing through a production well may in some instances crack to non-condensable compounds due to increased temperature at a production well.

Therefore, a location of a production well with respect to a heat source may be selected to increase a non-condensable gas fraction of the produced formation fluids. In addition, a location of a production well with respect to a heat source may be selected such that a non-condensable gas fraction of produced formation fluids may be larger than a condensable gas fraction of the produced formation fluids.

A carbon number distribution of a produced formation fluid may indicate a quality of the produced formation fluid. In general, condensable hydrocarbons with low carbon numbers are considered to be more valuable than condensable hydrocarbons having higher carbon numbers.
Low carbon numbers may include, for example, carbon numbers less than about 25. High carbon numbers may include carbon numbers greater than about 25. In an embodiment, an in situ conversion process for hydrocarbons may include providing heat to at least a portion of a formation and allowing heat to transfer such that heat may produce pyrolyzati,on fluids such that a majority of the pyrolyzation fluids ha-\,e carbon numbers of less than approximately 25.

In an embodiment, an in situ conversion process for hydrocarbons may include providing heat to at least a portion of a hydrocarbon containing formation at a rate sufficient to alter and/or control production of olefins.
For example, the process may include heating the portion at a rate to produce formation fluids having an olefin content of less than about 10% by weight of condensable hydrocarbons of the formation fluids. Reducing olefin production may substantially reduce coating of a pipe surface by such olefins, thereby reducing difficulty associated with transporting hydrocarbons through such piping. Reducing olefin production may also tend to inhibit polymerization of hydrocarbons during pyrolysis, thereby increasing permeability in the formation and/or enhancing the quality of produced fluids (e.g., by lowering the carbon number distribution, increasing API
gravity, etc.).

In some embodiments, however, the portion may be heated at a rate to selectively increase the olefin content of condensable hydrocarbons in the produced fluids. For example, olefins may be separated from such condensable hydrocarbons and may be used to produce additional products.

In some embodiments, the portion may be heated at a rate to selectively increase the content of phenol and substituted phenols of condensable hydrocarbons in the produced fluids. For example, phenol and/or substituted phenols may be separated from such condensable hydrocarbons and may be used to produce additional products. The resource may, in some embodiments, be selected to enhance production of phenol and/or substituted phenols.

Hydrocarbons in the produced fluids may include a mixture of a number of different components, some of which are condensable and some of which are not. The fraction of non-condensable hydrocarbons within the produced fluid may be altered and/or controlled by altering, controlling, and/or maintaining a temperature within a pyrolysis temperature range in a heated portion of the hydrocarbon containing formation. Additionally, the fraction of non-condensable hydrocarbons within the produced fluids may be altered and/or controlled by altering, controlling, and/or maintaining a pressure within the heated portion. In some embodiments, surface facilities may be configured to separate condensable and non-condensable hydrocarbons of a produced fluid.

In some embodiments, the non-condensable hydrocarbons may include, but are not limited to, hydrocarbons having less than about 5 carbon atoms, H2, C02, ammonia, H2S, N2 and/or CO. In certain embodiments, non-condensable hydrocarbons of a fluid produced from a portion of a hydrocarbon containing formation may have a weight ratio of hydrocarbons having carbon numbers from 2 through 4 ("C2_4" hydrocarbons) to methane of greater than about 0.3, greater than about 0.75, or greater than about 1 in some circumstances. For example, non-condensable hydrocarbons of a fluid produced from a portion of an oil shale or heavy hydrocarbon containing formation may have a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, of greater than approximately 1.
In addition, non-condensable hydrocarbons of a fluid produced from a portion of a coal containing formation may have a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, of greater than approximately 0.3.

Such weight ratios of C2_4 hydrocarbons to methane are believed to be beneficial as compared to similar weight ratios produced from other formations. Such weight ratios indicate higher amounts of hydrocarbons with 2, 3, and/or 4 carbons (e.g., ethane, propane, and butane) than is normally present in gases produced from formations. Such hydrocarbons are often more valuable.
Production of hydrocarbons with such weight ratios is believed to be due to the conditions applied to the formation during pyrolysis (e.g., controlled heating and/or pressure used in reducing environments, or at least non-oxidizing envi.ronments). It is believed that in such conditions longer chain hydrocarbons can be more easily broken down to form substantially smaller (and in many cases more saturated) compounds such as C2-4 hydrocarbons. The C2-4 hydrocarbons to methane weight ratio may vary depending on, for example, a temperature of the heated portion and a heating rate of the heated portion.
In certain embodiments, the API gravity of the hydrocarbons in a fluid produced from a hydrocarbon containing formation may be approximately 25 or above (e.g., 30, 40, 50, etc.).
Methane and at least a portion of ethane may be separated from non-condensable hydrocarbons in the produced fluid and may be utilized as natural gas. A
portion of propane and butane may be separated from non-condensable hydrocarbons of the produced fluid. In addition, the separated propane and butane may be utilized as fuels or as feedstocks for producing other hydrocarbons. A portion of the produced fluid having carbon numbers less than 4 may be reformed, as described herein, in the formation to produce additional H2 and/or methane. In addition, ethane, propane, and butane may be separated from the non-condensable hydrocarbons and may be used to generate olefins.
The non-condensable hydrocarbons of fluid produced from a hydrocarbon containing formation may have a H2 content of greater than about 5% by weight, greater than 10% by weight, or even greater than 15% by weight. The H2 may be used, for example, as a fuel for a fuel cell, to hydrogenate hydrocarbon fluids in situ, and/or to hydrogenate hydrocarbon fluids ex situ. In addition, presence of H2 within a formation fluid in a heated section of a hydrocarbon containing formation is believed to increase the quality of produced fluids. In certain embodiments, the hydrogen to carbon atomic ratio of a produced fluid may be at least approximately 1.7 or above. For example, the hydrogen to carbon atomic ratio of a produced fluid may be approximately 1.8, approximately 1.9, or greater.

The non-condensable hydrocarbons may include some hydrogen sulphide. The non-condensable hydrocarbons may be treated to separate the hydrogen sulphide from other compounds in the non-condensable hydrocarbons. The separated hydrogen sulphide may be used to produce, for example, sulfuric acid, fertilizer, and/or elemental sulfur. .

In certain embodiments, fluid produced from a hydrocarbon containing formation by an in situ conversion process may include carbon dioxide. Carbon dioxide produced from the formation may be usec:, for example, for enhanced oil recovery, as at least a portion of a feedstock for production of urea, and/or may be reinjected into a hydrocarbon containing formation for synthesis gas production and/or coal bed methane production.

Fluid produced from a hydrocarbon containing formation by an in situ conversion process may include carbon monoxide. Carbon monoxide produced from the formation may be used, for example, as a feedstock for a fuel cell, as a feedstock for a Fischer Tropsch process, as a feedstock for production of methanol, and/or as a feedstock for production of methane.

The condensable hydrocarbons of the produced.fluids may be separated from the fluids. In an embodiment, a condensable component may include condensable hydrocarbons and compounds found in an aqueous phase.
The aqueous phase may be separated from the condensable component. The ammonia content of the total produced fluids may be greater than about 0.1 % by weight of the fluid, greater than about 0.5 % by weight of the fluid, and, in some embodiments, up to about 10 % by weight of the produced fluids. The ammonia may be used to produce, for example, urea.

Certain embodiments of a fluid may be produced in which a majority of hydrocarbons in the produced fluid have a carbon number of less than approximately 25.
Alternatively, less than about 15% by weight of the hydrocarbons in the condensable hydrocarbons have a carbon numbergreater than approximately 25. In some embodiments, less than about 5% by weight of hydrocarbons in the condensable hydrocarbons have a carbon number greater than approximately 25, and/or less than about 2%
by weight of hydrocarbons in the conde.isable hydrocarbons .have a carbon number greater than approximately 25.

In certain embodiments, a fluid produced from a formation (e.g., a coal containing formation) may include oxygenated hydrocarbons. For example, condensable hydrocarbons of the produced fluid may include an amount of oxygenated hydrocarbons greater than about 5% by weight of the condensable hydrocarbons. Alternatively, the condensable hydrocarbons may include an amount of oxygenated hydrocarbons greater than about 1.0% by weight of the.condensable hydrocarbons. Furthermore, the condensable hydrocarbons may include an amount of oxygenated hydrocarbons greater than about 1.5% by weight of the condensable hydrocarbons or greater than about 2.0% by weight of the condensable hydrocarbons. In an embodiment, the oxygenated hydrocarbons may include, but are not limited to, phenol and/or substituted phenols.
In some embodiments, phenol and substituted phenols may have more economic value than other products produced from an in situ conversion process. Therefore, an in situ conversion process may be utilized to produce phenol and/or substituted phenols. For example, generation of phenol and/or substituted phenols may increase when a fluid pressure within the formation is maintained at a lower pressure.

In some embodiments, condensable hydrocarbons of a fluid produced from a hydrocarbon containing formation may also include olefins. For example, an olefin content of the condensable hydrocarbons may be in a range from about 0.1% by weight to about 15% by weight.
Alternatively, an olefin content of the condensable hydrocarbons may also be within a range from about 0.1%
by weight to about 5% by weight. Furthermore, an olefin content of the condensable hydrocarbon~ may also be within a range from about 0.1% by weight to about 2.5% by weight. An olefin content of the condensable hydrocarbons may be altered and/or controlled by controlling a pressure and/or a temperature within the formation. For example, olefin content of the condensable hydrocarbons may be reduced by selectively increasing pressure within the formation, by selectively decreasing temperature within the formation, by selectively reducing heating rates within the formation, and/or by selectively increasing hydrogen partial pressures in the formation. In some embodiments, a reduced olefin content of the condensable hydrocarbons may be preferred. For example, if a portion of the produced fluids is used to produce motor fuels, a reduced olefin content may be desired.

In alternate embodiments, a higher olefin content may be preferred. For example, if a portion of the condensable hydrocarbons may be sold, a higher olefin content may be preferred due to a high economic value of olefin products. In some embodiments, olefins may be separated from the produced fluids and then sold and/or used as a feedstock for the production of other compounds.

Non-condensable hydrocarbons of a produced fluid may also include olefins. For example, an olefin content of the non-condensable hydrocarbons may be gauged using an ethene/ethane molar ratio. In certain embodiments, the ethene/ethane molar ratio may range from about 0.001 to about 0.15.

Fluid produced from a hydrocarbon containing formation may include aromatic compounds. For example, the condensable hydrocarbons may include an amount of aromatic compounds greater than about 20% by weight or about 25% by weight of the condensable hydrocarbons.
Alternatively, the condensable hydrocarbons may include an amount of aromatic compounds greater than about 30% by weight of the condensable hydrocarbons. The condensable hydrocarbons may also include relatively low amounts of compounds with more than two rings in them (e.g., tri-aromatics or above). For example, the condensable hydrocarbons may include less than about 1% by weight or less than about 2% by weight of tri-aromatics or above in the condensable hydrocarbons. Alternatively, the condensable hydrocarbons may include less than about 5%
by weight of tri-aromatics or above in the condensable hydrocarbons.

In particular, in certain embodiments, asphaltenes (i.e., large multi-ring aromatics that may be substantially soluble in hydrocarbons) make up less than about 0.1% by weight of the condensable hydrocarbons.
For example, the condensable hydrocarbons may include an asphaltene component of from about 0.0% by weight to about 0.1% by weight or, in some embodiments, less than about 0.3% by weight.

Condensable hydrocarbons of a produced fluid may also include relatively large amounts of cycloalkanes. For example, the condensable hydrocarbons may include a cycloalkane component of from about 5% by weight to about 30% by weight of the condensable hydrocarbons.

In certain embodiments, the condensable hydrocarbons of a fluid produced from a formatiori may include compounds containing nitrogen. For example, les.s than about 1% by weight (when calculated on an elemental basis) of the condensable hydrocarbons may be nitrogen (e.g., typically the nitrogen may be in nitrogen containing compounds such as pyridines, amines, amides, carbazoles, etc. ) .

In certain embodiments, the condensable hydrocarbons of a fluid produced from a formation may include compounds containing oxygen. For example, in certain embodiments (e.g., for oil shale and heavy hydrocarbons) less than about 1% by weight (when calculated on an elemental basis) of the condensable hydrocarbons may be oxygen containing compounds (e.g., typically the oxygen may be in oxygen containing compounds such as phenol, substituted phenols, ketones, etc.). In certain other embodiments, (e.g., for coal containing formations) between about 5% by weight and about 30% by weight of the condensable hydrocarbons may typically include oxygen containing compounds such as phenols, substituted phenols, ketones, etc. In some instances, certain compounds containing oxygen (e.g., phenols) may be valuable and, as such, may be economically separated from the produced fluid.

In certain embodiments, condensable hydrocarbons of the fluid produced from a formation may include compounds containing sulfur. For example, less than about 1% by weight (when calculated on an elemental basis) of the condensable hydrocarbons may be sulfur (e.g., typically the sulfur containing compounds may include compounds such as thiophenes, mercaptans, etc.).

E'urthermore, the fluid produced from the formation may include ammonia (typically the ammonia may condense with water, if any, produced from the formation). For example, the fluid produced from the formation may in certain embodiments include about 0.05% or more by weight of ammonia. Certain formations (e.g., coal and/or oil shale) may produce larger amounts of ammonia (e.g., up to about 10% by weight of the total fluid produced may be ammonia).

In addition, a produced fluid from the formation may also include molecular hydrogen (H2). For example, the fluid may include a H2 content between about 10% to about 80% by volume of the non-condensable hydrocarbons.
In some embodiments, at least about 15% by weight of a total organic carbon content of hydrocarbons in the portion may be transformed into hydrocarbon fluids.
A total potential amount of products that may be produced from hydrocarbons may be determined by a Fischer Assay. The Fischer Assay is a standard method that involves heating a sample of hydrocarbons to approximately 500 C in one hour, collecting products produced from the heated sample, and quantifying the products. In an embodiment, a method for treating a hydrocarbon containing formation in situ may include heating a section of the formation to yield greater than about 60% by weight of the potential amount of products from the hydrocarbons as measured by the Fischer Assay.
In certain embodiments, heating of the selected section of the formation may be controlled to pyrolyze at least about 20% by weight (or in some embodiments about 25% by weight) of the hydrocarbons within the selected section of the formation. Conversion of hydrocarbons withih a formation may be limited to inhibit subsidence of the formation.

Heating at least a portion of a formation may cause at least some of the hydrocarbons within the portion to pyrolyze, thereby forming hydrocarbon fragments. The hydrocarbon fragments may be reactive and may react with other compounds in the formation and/or with other hydrocarbon fragments produced by pyrolysis. Reaction of the hydrocarbon fragments with other compounds and/or with each other, however, may reduce production of a selected product. A reducing agent in or provided to the portion of the formation during heating, however, may increase production of the selected product. An example of a reducing agent may include, but may not be limited to, H2. For example, the reducing agent may react with the hydrocarbon fragments to form a selected.product.

In an embodiment, molecular hydrogen may be provided to the formation to create a reducing environment. A
hydrogenation reaction between the molecular hydrogen and at least some of the hydrocarbons within a portion of the formation may generate heat. The generated heat may be used to heat the portion of the formation. Molecular hydrogen may also be generated within the portion of the formation. In this manner, the generated H2 may be used to hydrogenate hydrocarbon fluids within a portion of a formation.

For example, H2 may be produced from a first portion of the hydrocarbon containing formation. The H2 may be produced as a component of a fluid produced from a first portion. For example, at least a portion of fluids produced from a first portion of the formation may be provided to a second portion of the formation to create a reducing environment within the second portion. The second portion of the formation may be heated as described herein. In addition, produced H2 may be provided to a second portion of the formation. For example, a partial pressure of H2 within the produced fluid may be greater than a pyrolysis H2 partial pressure, as measured at a well from which the produced fluid may be produced.

For example, a portion of a hydrocarbon containing formation may be heated in a reducing environment. The presence of a reducing agent during pyrolysis of at least some of the hydrocarbons in the heated portion may reduce (e.g., at least partially saturate) at least some of the pyrolyzed product. Reducing the pyrolyzed product may decrease a concentration of olefins in hydrocarbon fluids. Reducing the pyrolysis products may improve the product quality of the hydroca-rbon fluids.

An embodiment of a method for treating a hydrocarbon containing formation in situ may include generating H2 and hydrocarbon fluids within the formation. In addition, the method may include hydrogenating the generated hydrocarbon fluids using the H2 within the formation. In some embodiments, the method may also include providing the generated H2 to a portion of the formation.

In an embodiment, a method of treating a portion of a hydrocarbon containing formation may include heating the portion such that a thermal conductivity of a selected section of the heated portion increases. For example, porosity and permeability within a selected section of the portion may increase substantially during heating such that heat may be transferred through the formation not only by conduction but also by convection and/or by radiation from a heat source. In this manner, such radiant and convective transfer of heat may increase an apparent thermal conductivity of the selected section and, consequently, the thermal diffusivity. The large apparent thermal diffusivity may make heating at least a portion of a hydrocarbon containing formation from heat sources feasible. For example, a combination of conductive, radiant, and/or convective heating may accelerate heating. Such accelerated heating may significantly decrease a time required for producing hydrocarbons and may significantly increase the economic feasibility of commercialization of an in situ conversion process. In a further embodiment, the in situ conversion process for a hydrocarbon containing formation may also include providing heat to the heated portion to increase a thermal conductivity of a selected section to greater than about 0.5 W/(m C) or about 0.6 W/(m C).

In some embodiments, an in situ conversion process for a coal formation may increase the rank level of coal within a heated portion of the coal. The increase in rank level, as assessed by the vitrinite reflectance, of the coal may coincide with a substantial change of the structure (e.g., molecular changes in the carbon structure) of the coal. The changed structure ofthe coal may have a higher thermal conductivity.
Thermal diffusivity within a hydrocarbon containing formation may vary depending on, for example, a density --of the hydrocarbon containing formation, a heat capacity 'of the formation, and a thermal conductivity of the formation. As pyrolysis occurs within a selected section, the hydrocarbon containing formation mass may be removed from the selected section. The removal of mass may include, but is not limited to, removal of water and a transformation of hydrocarbons to formation fluids.
For example, a lower thermal conductivity may be.expected as water is removed from a coal containing formation.
This effect may vary significantly at different depths.
At greater depths a lithostatic pressure may be higher, and may close certain openings (e.g., cleats and/or fractures) in the coal. The closure of the coal openings may increase a thermal conductivity of the coal. In some embodiments, a higher thermal conductivity may be observed due to a higher lithostatic pressure.

In some embodiments, an in situ conversion process may generate molecular hydrogen during the pyrolysis process. In addition, pyrolysis tends to increase the porosity/void spaces in the formation. Void spaces in the formation may contain hydrogen gas generated by the pyrolysis process. Hydrogen gas may have about six times the thermal conductivity of nitrogen or air. This may raise the thermal conductivity of the formation.

Certain embodiments described herein will in many instances be able to economically treat formations that were previously believed to be uneconomical. Such treatment will be possible because of the surprising increases in thermal conductivity and thermal diffusivity that can be achieved with such embodiments. These surprising results are illustrated by the fact that prior literature indicated that certain hydrocarbon containing formations, such as coal, exhibited relatively low values for thermal conductivity and thermal diffusivity when heated. For example, in government report No. 8364 by J.
M. Singer and R. P. Tye entitled "Thermal, Mechanical, and Physical Properties of Selected Bituminous Coals and Cokes," U.S. Department of the Interior, Bureau of Mines (1979*), the authors report the thermal conductivity and thermal diffusivity for four bituminous coals. This government report includes graphs of thermal conductivity and diffusivity that show relatively low values up to about 400 C (e.g., thermal conductivity is about 0.2 W/(m C) or below, and thermal difiusivity is below about 1.7 x 10-3 cm2/s). This government report states that "coals and cokes are excellent thermal insulators".

In contrast, in certain embodiments described herein hydrocarbon containing resources (e.g., coal) may be treated such that the thermal conductivity and thermal diffusivity are significantly higher (e.g., thermal conductivity at or above about 0.5 W/(m C) and thermal diffusivity at or above 4.1 x 10-3 cm2/s) than would be expected based on previous literature such as government report No. 8364. If treated as described in certain embodiments herein, coal does not act as "an excellent thermal insulator". Instead, heat can and does transfer and/or diffuse into the formation at significantly higher, (and better) rates than would be expected according to the literature, thereby significantly enhancing economic viability of treating the formation.

In an embodiment, heating a portion of a hydrocarbon containing formation in situ to a temperature less than an upper pyrolysis temperature may increase permeability of the heated portion. For example, permeability may increase due to formation of fractures within the heated portion caused by application of heat. As a temperature of the heated portion increases, water may be removed due to vaporization. The vaporized water may escape and/or be removed from the formation. Removal of water may also increase the permeability of the heated portion. In addition, permeability of the heated portion may also increase as a result of production of hydrocarbons from pyrolysis of at least some of the hydrocarbons within the heated portion on a macroscopic scale. In an embodiment, a permeability of a selected section within a heated portion of a hydrocarbon containing formation may be substantially uniform. For example, heating by conduction may be substantially uniform, and thus a permeability created by conductive heating may also be substantially uniform. In the context of this patent "substantially uniform permeability" means that the assessed (e.g., calculated or estimated) permeability of any selected portion in the formation does not vary by more than a factor of 10 from the assessed average permeability of such selected portion.

Perineability of a selected section within the heated portion of the hydrocarbon containing formation may also rapidly increase while the s,elected section is heated by conduction. For example, permeability of an impermeable hydrocarbon containing formation may be less than about 0.1 millidarcy (9.9 x 10-17 m2) before treatment. In some embodiments, pyrolyzing at least a portion of a hydrocarbon containing formation may increase a permeability within a selected section of the portion to greater than about 10 millidarcy, 100 millidarcy, 1 Darcy, 10 Darcy, 20 Darcy, or 50 Darcy. Therefore, a permeability of a selected section of the portion may increase by a factor of more than about 1,000, 10,000, or 100,000.

In some embodiments, superposition (e.g., overlapping) of heat from one or more heat sources may result in substantially uniform heating of a portion of a hydrocarbon containing formation. Since formations during heating will typically have temperature profiles throughout them, in the context of this patent "substantially uniform" heating means heating such that the temperatures in a majority of the section do not vary by more than 100 C from the assessed average temperature in the majority of the selected section (volume) being treated.

Substantially uniform heating of the hydrocarbon containing formation may result in a substantially uniform increase in permeability. For example, uniformly heating may generate a series of substantially uniform fractures within the heated portion due to thermal stresses generated in the formation. Heating substantially uniformly may generate pyrolysis fluids from the portion in a substantially homogeneous manner.
Water removed due to vaporization and production may result in increased permeability of the heated portion.
In addition to creating fractures due to thermal stresses, fractures may also be generated due to fluid pressure increase. As fluids are generated within the heated portion a fluid pressure within the heated portion may also increase. As the fluid pressure approaches a lithostatic pressure of the heated portion, fractures may be generated. Substantially uniform heating and homogeneous generation of fluids may generate substantially uniform fractures within the heated portion. In some embodiments, a permeability of a heated section of a hydrocarbon containing formation may not vary by more than a factor of about 10.

Removal of hydrocarbons due to treating at least a portion of a hydrocarbon containing formation, as described in any of the above embodiments, may also occur on a microscopic scale. Hydrocarbons may be removed from micropores within the portion due to heating. Micropores may be generally defined as pores having a cross-sectional dimension of less than about 1000 A. In this manner, removal of solid hydrocarbons may result in a substantially uniform increase in porosity within at least a selected section of the heated portion. Heating the portion of a hydrocarbon containing formation, as described in any of the above embodiments, may substantially uniformly increase a porosity of a selected section within the heated portion. In the context of this patent "substantially uniform porosity" means that the assessed (e.g., calculated or estimated) porosity of any selected portion in the formation does not vary by more than about 25% from the assessed average porosity of such selected portion.
Physical characteristics of a portion of a hydrocarbon containing formation after pyrolysis may be similar to those of a porous bed. For example, a portion of a hydrocarbon containing formation after pyrolysis may include particles having sizes of about several millimeters. Such physical characteristics may differ from physical characteristics of a hydrocarbon containing formation that may be subjected to injection of gases that burn hydrocarbons in order to heat the hydrocarbons.

Such gases injected into virgin or fractured formations may tend to channel and may not be uniformly distributed throughout the formation. In contrast, a gas injected into a pyrolyzed portion of a hydrocarbon containing formation may readily and substantially uniformly contact the carbon and/or hydrocarbons remaining in the formation. In addition, gases produced by heating the hydrocarbons may be transferred a significant distance within the heated portion of the formation with a minimal pressure loss. Such transfer of gases may be particularly advantageous, for example, in treating a steeply dipping hydrocarbon containing formation.

Synthesis gas may be produced from a portion of a hydrocarbon containing formation containing, e.g., coal, oil shale, other kerogen containing formations, heavy hydrocarbons (tar sands, etc.) and other bitumen containing formations. The hydrocarbon containing formation may be heated prior to synthesis gas generation to produce a substantially uniform, relatively high permeability formation. In an embodiment, synthesis gas production may be commenced after production of pyrolysis fluids has been substantially exhausted or becomes uneconomical. Alternately, synthesis gas generation may be commenced before substantial exhaustion or uneconomical pyrolysis fluid production has been achieved if production of synthesis gas will be more economically favourable. Formation temperatures will usually be higher than pyrolysis temperatures during synthesis gas generation. Raising the formation temperature from pyrolysis temperatures to synthesis gas generation temperatures allows further utilization of heat applied to the formation to pyrolyze the formation. While raising a temperature of a formation from pyrolysis temperatures to synthesis gas temperatures, methane and/or H2 may be produced from the formation.

Producing synthesis gas from a formation from which pyrolyzation fluids have been previously removed allows a synthesis gas to be produced that includes mostly H2, CO, water and/or C02. Produced synthesis gas, in certain embodiments, may have substantially no hydrocarbon component unless a separate source hydrocarbon stream is introduced into the formation with or in addition to the synthesis gas producing fluid. Producing synthesis gas from a substantially uniform, relatively high permeability formation that was formed by slowly heating a formation through pyrolysis temperatures may allow for easy introduction of a synthesis gas generating fluid into the formation, and may allow the synthesis gas generating fluid to contact a relatively large portion of the formation. The synthesis gas generating fluid can do so because the permeability of the formation has been increased during pyrolysis and/or because the surface area per volume in the formation has increased during pyrolysis. The relatively large surface area (e.g., "contact area") in the post-pyrolysis formation tends to allow synthesis gas generating reactions to be substantially at equilibrium conditions for C, H2, CO, water and C02. Reactions in which methane is formed may, however, not be at equilibrium because they are kinetically limited. The relatively high, substantially uniform formation permeability may allow production wells to be spaced farther apart than production wells used during pyrolysis of the formation.
A temperature of at least a portion of a formation that is used to generate synthesis gas may be raised to a synthesis gas generating temperature (e.g., between about 400 C and about 1200 C). In some embodiments composition of produced synthesis gas may be affected by formation temperature, by the temperature of the formation adjacent to synthesis gas production wells, and/or by residence time of the synthesis gas components.
A relatively low synthesis gas generation temperature may produce a synthesis gas having a high H2 to CO ratio, but the produced synthesis gas may also include a large portion of other gases such as water, C02, and methane.
A relatively high formation temperature may produce a synthesis gas having a H2 to CO ratio that approaches 1, and the stream may include mostly (and in some cases substantially only) H2 and CO. If the synthesis gas generating fluid is substantially pure steam, then the H2 to CO ratio may approach 1 at relatively high temperatures. At a formation temperature of about 700 C, the formation may produce a synthesis gas with a H2 to CO ratio of about 2 at a certain pressure. The composition of the synthesis gas tends to depend on the nature of the synthesis gas generating fluid.

Synthesis gas generation is generally an endothermic process... Heat may be added to a portion of a formation during synthesis gas production to keep formation temperature at a desired synthesis gas generating temperature or above a minimum synthesis gas generating temperature. Heat may be added to the formation from heat sources, from oxidation reactions within the portion, and/or from introducing synthesis gas generating fluid into the formation at a higher temperature than the temperature of the formation.

An oxidant may be introduced into a portion of the formation with synthesis gas generating fluid. The oxidant may exothermically react with carbon within the portion of the formation to heat the formation.
Oxidation of carbon within a formation may allow a portion of a formation to be economically heated to relatively high synthesis gas generating temperatures.
The oxidant may also be introduced into the formation without synthesis gas generating fluid to heat the portion. Using an oxidant, or an oxidant and heat sources, to heat the portion of the formation may be significantly more favourable than heating the portion of the formation with only the heat sources. The oxidant may be, but is not limited to, air, oxygen, or oxygen enriched air. The oxidant may react with carbon in the formation to produce C02 and/or CO. The use of air, or oxygen enriched air (i.e., air with an oxygen content greater than 21% by volume), to generate heat within the formation may cause a significant portion of N2 to be present in produced synthesis gas. Temperatures in the formation may be maintained below temperatures needed to generate oxides of nitrogen (NOx), so that little or no NOx compounds may be present in produced synthesis gas.

A mixture of steam and oxygen, or steam and air, may be substantially continuously injected into a formation.
If injection of steam and oxygen is used for synthesis gas production, the oxygen may be produced on site by electrolysis of water utilizing direct current output of a fuel cell. H2 produced by the electrolysis of water may be used as a fuel stream for the fuel cell. 02 produced by the electrolysis of water may be injected into the hot formation to raise a temperature of the formation.

Heat sources and/or production wells within a formation for pyrolyzing and producing pyrolysis fluids from the formation may be utilized for different purposes during synthesis gas production. A well that was used as a heat source or a production well during pyrolysis may be used as an injection well to introduce synthesis gas producing fluid into the formation. A well that was used as a heat source or a production well during pyrolysis may be used as a production well during synthesis gas generation. A well that was used as a heat source or a production well during pyrolysis may be used as a heat source to heat the formation during synthesis gas generation. Synthesis gas production wells may be spaced further apart than pyrolysis production wells because of the relatively high, substantially uniform permeability of the formation. Synthesis gas production wells may be heated to relatively high temperatures so that a portion of the formation adjacent to the production well is at a temperature that will produce a desired synthesis gas composition. Comparatively, pyrolysis fluid production wells may not be heated at all, or may only be heated to a temperature that will inhibit condensation of pyrolysis fluid within the production well.

Synthesis gas may be produced from a dipping formation from wells used during pyrolysis of the formation. As shown in FIG. 4, synthesis gas production wells 206 may be located above and down dip from an injection well 208. Hot synthesis gas producing fluid may be introduced into injection well 208. Hot synthesis gas fluid that moves down dip may generate synthesis gas that is produced through synthesis gas production wells 206. Synthesis gas generating fluid that moves up dip may generate synthesis gas in a portion of the formation that is at synthesis gas generating temperatures. A
portion of the synthesis gas generating fluid and generated synthesis gas that moves up dip above the portion of the formation at synthesis gas generating temperatures may heat adjacent formation. The synthesis gas generating fluid that moves up dip may condense, heat adjacent portions of formation, and flow downwards towards or into a portion of the formation at synthesis gas generating temperature. The synthesis gas generating fluid may then generate additional synthesis gas.
Synthesis gas generating fluid may be any fluid capable of generating H2 and CO within a heated portion of a formation. Synthesis gas generating fluid may include water, 02, air, C02, hydrocarbon fluids, or combinations thereof. Water may be introduced into a formation as a liquid or as steam. Water may react with carbon in a formation to produce H2, CO, and C02. C02 may react with hot carbon to form CO. Air and 02 may be oxidants that react with carbon in a formation to generate heat and form C02, CO, and other compounds.
Hydrocarbon fluids may react within a formation to form H2, CO, C02, H2O, coke, methane and/or other light hydrocarbons. Introducing low carbon number hydrocarbons (i.e., compounds with carbon numbers less than 5) may produce additional H2 within the formation. Adding higher carbon number hydrocarbons to the formation may increase an energy content of generated synthesis gas by having a significant methane and other low carbon number compounds fraction within the synthesis gas.

Water provided as a synthesis gas generating fluid may be derived from numerous different sources. Water may be produced during a pyrolysis stage of treating a formation. The water may include some entrained hydrocarbon fluids. Such fluid may be used as synthesis gas generating fluid. Water that includes hydrocarbons may advantageously generate additional H2 when used as a synthesis gas generating fluid. Water produced from water pumps that inhibit water flow into a portion of formation being subjected to an in situ conversion process may provide water for synthesis gas generation.

A low rank kerogen resource or hydrocarbons having a relatively high water content (i.e. greater than about 20% H20 by weight) may generate a large amount of water and/or C02 if subjected to an in situ conversion process.

The water and C02 produced by subjecting a low rank kerogen resource to an in situ conversion process may be used as a synthesis gas generating fluid.

Reactions involved in the formation of synthesis gas may include, but are not limited to:

(1) C + H20 H2 + CO
(2) C + 2H20 2H2 + C02 (3) C + C02 2C0 Thermodynamics allows the following reactions to proceed:

(4) 2C + 2H20 '~* CH4 + C02 (5) C + 2H2 '~* CH4 However, kinetics of the reactions are slow in certain embodiments so that relatively low amounts of methane are formed at formation conditions from Reactions (4) and (5).

In the presence of oxygen, the following reaction may take place to generate carbon dioxide and heat:
(6) C + 02 -> C02 Equilibrium gas phase compositions of coal in contact with steam may provide an indication of the compositions of components produced in a formation during synthesis gas generation. Equilibrium composition data for H2, carbon monoxide, and carbon dioxide may be used to determine appropriate operating conditions such as temperature that may be used to produce a synthesis gas having a selected composition. Equilibrium conditions may be approached within a formation due to a high, substantially uniform permeability of the formation.
Composition data obtained from synthesis gas production may in many instances deviate by less than 10% from equilibrium values.

In one embodiment, a composition oi the produced synthesis gas can be changed by injecting additional components into the formation along with steam. Carbon dioxide may be provided in the synthesis gas generating fluid to substantially inhibit production of carbon dioxide produced from the formation during synthesis gas generation. The carbon dioxide may shift the equilibrium of reaction (2) to the left, thus reducing the amount of carbon dioxide generated from formation carbon. The carbon dioxide may also react with carbon in the formatioan to generate carbon monoxide. Carbon dioxide may be separated from the synthesis gas and may be re-injected into the formation with the synthesis gas generating fluid. Addition of carbon dioxide in the synthesis gas generating fluid may, however, reduce the production of hydrogen.

FIG. 29 depicts a schematic diagram of use of water recovered from pyrolysis fluid production being used to generate synthesis gas. Heat source 801 with electric heater 803 produces pyrolysis fluid 807 from first section 805 of the formation. Produced pyrolysis fluid 807 may be sent to separator 809. Separator 809 may include a number of individual separation units and processing units that produce aqueous stream 811, vapour stream 813, and hydrocarbon condensate stream 815.
Aqueous stream 811 from the separator 809 may be combined with synthesis gas generating fluid 818 to form synthesis gas generating fluid 821. Synthesis gas generating fluid*821 may be provided to injection well 817 and introduced to second portion 819 of the formation.
Synthesis gas 823 may be produced from synthesis gas production well 825.

FIG. 30 depicts a schematic diagram of an embodiment of a system for synthesis gas production in which carbon dioxide from produced synthesis gas is injected into a formation. Synthesis gas 830 may be produced from formation 832 through production well 834. Gas separation unit 836 may separate a portion of carbon dioxide from the synthesis gas 830 to produce C02 stream 838 and remaining synthesis gas stream 840. The C02 stream 838 may be mixed with synthesis gas producing fluid stream 842 that is introduced into the formation 832 through injection well 837, and/or the C02 may be separately introduced into the formation. This may limit conversion of carbon within the formation to C02 and/or may increase an amount of CO generated within the formation.

Synthesis gas generating fluid may be introduced into a formation in a variety of different ways. Steam may be injected into a heated hydrocarbon containing formation at a lowermost portion of the heated formation.
Alternatively, in a steeply dipping formation, steam may be injected up dip with synthesis gas production down dip. The injected steam may pass through the remaining hydrocarbon containing formation to a production well.
In addition, endothermic heat of reaction may be provided to the formation with heat sources disposed along a path of the injected steam. In alternate embodiments, steam may be injected at a plurality of locations along the hydrocarbon containing formation to increase penetration of the steam throughout the formation. A line drive pattern of locations may also be utilized. The line drive pattern may include alternating rows of steam injection wells and synthesis gas production wells.

At relatively low pressures, and temperatures below about 400 C, synthesis gas reactions are relatively slow. At relatively low pressures, and temperatures between about 400 C and about 700 C, Reaction (2) tends to be the predominate reaction and the synthesis gas composition is primarily hydrogen and carbon dioxide. At relatively low pressures, and temperatures greater than about 700 C, Reaction (1) tends to be the predominate reaction and the synthesis gas composition is primarily hydrogen and carbon monoxide.

Advantages of a lower temperature synthesis gas reaction may include lower heat requirements, cheaper metallurgy and less endothermic reactions (especially when methane formation takes place). An advantage of a higher temperature synthesis gas reaction is that hydrogen and carbon monoxide may be used as feedstock for other processes (e.g., Fischer-Tropsch processes).

A pressure of the hydrocarbon containing formation may be maintained at relatively high pressures during synthesis gas production. The pressure may range from atmospheric pressure to a lithostatic pressure of the formation. Higher formation pressures may allow generation of electricity by passing produced synthesis gas through a turbine. Higher formation pressures may allow for smaller collection conduits to transport produced synthesis gas, and reduced downstream compression requirements on the surface.

In some embodiments, synthesis gas may be produced from a portion of a formation in a substantially continuous manner. The portion may be heated to a desired synthesis gas generating temperature. A
synthesis gas generating fluid may be introduced into the portion. Heat may be added to, or generated within, the portion of the formation during introduction of the synthesis gas generating fluid to the portion. The added heat compensates for the loss of heat due to the endothermic synthesis gas reactions as well as heat losses to the top and bottom layers, etc. In other embodiments, synthesis gas may be produced in a substantially batch manner. The portion of the formation may be heated, or heat may be generated within the portion, to raise a temperature of the portion to a high synthesis gas generating temperature. Synthesis gas generating fluid may then be added to the portion until generation of synthesis gas reduces the temperature of the formation below a temperature that produces a desired synthesis gas composition. Introduction of the synthesis gas generating fluid may then be stopped. The cycle may be repeated by reheating the portion of the formation to the high synthesis gas generating temperature and adding synthesis gas generating fluid after obtaining the high synthesis gas generating temperature. Composition of generated synthesis gas may be monitored to determine when addition of synthesis gas generating fluid to the formation should be stopped.

FIG. 31 illustrates a schematic of an embodiment of a continuous synthesis gas production system. FIG. 31 includes a formation with heat injection wellbore 850 and heat injection wellbore 852. The wellbores may be members of a larger pattern of wellbores placed throughout a portion of the formation. A portion of a formation may be heated to synthesis gas generating temperatures by heating the formation with heat sources, by injecting an oxidizing fluid, or by a combination thereof. Oxidizing fluid 854, such as air or oxygen, and synthesis gas generating fluid 856, such as steam, may be injected into wellbore 850. In one embodiment, the ratio of oxygen to steam may be approximately 1:2 to approximately 1:10, or approximately 1:3 to approximately 1:7 (e.g., about 1:4).

In situ combustion of hydrocarbons may heat region 858 of the formation between wellbores 850 and 852.
Injection of the oxidizing fluid may heat region 858 to a particular temperature range, for example, between about 600 C and about 700 C. The temperature may vary, however, depending on a desired composition of the synthesis gas. An advantage of the continuous production method may be that the temperature across region 858 may be substantially uniform and substantially constant with time once the formation has reached substantial thermal equilibrium. Continuous production may also eliminate a need for use of valves to reverse injection directions on a substantially frequent basis. Further, continuous production may reduce temperatures near the injections wells due to endothermic cooling from the synthesis gas reaction that may occur in the same region as oxidative heating. The substantially constant temperature may allow for control of synthesis gas composition. Produced synthesis gas 860 may exit continuously from wellbore 852.
In an embodiment, it may be desirable to use oxygen rather than air as oxidizing fluid 854 in continuous production. If air is used, nitrogen may need to be separated from the synthesis gas. The use of oxygen as oxidizing fluid 854 may increase a cost of production due to the cost of obtaining substantially pure oxygen. The cryogenic nitrogen by-product obtained from an air separation plant used to produce the required oxygen may, however, be used in a heat exchanger to condense hydrocarbons from a hot vapour stream produced during pyrolysis of hydrocarbons. The pure nitrogen may also be used for ammonia production.

FIG. 32 illustrates a schematic of an embodiment of a batch production of synthesis gas in a hydrocarbon containing formation. Wellbore 870 and wellbore 872 may be located within a portion of the formation. The wellbores may be members of a larger pattern of wellbores throughout the portion of the formation. Oxidizing fluid 874, such as air or oxygen, may be injected into wellbore 870. Oxidation of hydrocarbons may heat region 876 of a formation between wellbores 870 and 872.
Injection of air or oxygen may continue until an average temperature of region 876 is at a desired temperature (e.g., between about 900 C and about 1000 C). Higher or lower temperatures may also be developed. A
temperature gradient may be formed in region 876 between wellbore 870 and wellbore 872. The highest temperature of the gradient may be located proximate to the injection wellbore 870.

When a desired temperature has been reached, or when oxidizing fluid has been injected for a desired period of time, oxidizing fluid injection may be lessened and/or ceased. A synthesis gas generating fluid 877, such as steam or water, may be injected into the injection wellbore 872 to produce synthesis gas. A back pressure of the injected steam or water in the injection wellbore may force the synthesis gas produced and un-reacted steam across region 876. A decrease in average temperature of region 876 caused by the endothermic synthesis gas reaction may be partially offset by the temperature gradient in region 876 in a direction indicated by arrow 878. Product stream 880 may be produced through heat source wellbore 870. If the composition of the product deviates substantially from a desired composition, then steam injection may cease, and air or oxygen injection may be reinitiated.
In one embodiment, synthesis gas of a selected composition may be produced by blending synthesis gas produced from different portions of the formation. A
first portion of a formation may be heated by one or more heat sources to a first temperature sufficient to allow generation of synthesis gas having a H2 to carbon monoxide ratio of less than the selected H2 to carbon monoxide ratio (e.g., about 1 or 2). A first synthesis gas generating fluid may be provided to the first portion to generate a first synthesis gas. The first synthesis gas may be produced from the formation. A second portion of the formation may be heated by one or more heat sources to a second temperature sufficient to allow generation of synthesis gas having a H2 to carbon monoxide ratio of greater than the selected H2 to carbon monoxide ratio (e.g., a ratio of 3 or more). A second synthesis gas generating fluid may be provided to the second portion to generate a second synthesis gas. The second synthesis gas may be produced from the formation.
The first synthesis gas may be blended with the second synthesis gas to produce a blend synthesis gas having a desired H2 to carbon monoxide ratio.

The first temperature may be substantially different than the second temperature. Alternatively, the first and second temperatures'may be approximately the same temperature. For example, a temperature sufficient to allow generation of synthesis gas having different compositions may vary depending on compositions of the first and second portions and/or prior pyrolysis of hydrocarbons within the first and secoiid portions. The first synthesis gas generating fluid may have substantially the same composition as the second synthesis gas generating fluid. Alternatively, the first synthesis gas generating fluid may have a different composition than the second synthesis gas generating fluid. Appropriate first and second synthesis generating fluids may vary depending upon, for example, temperatures of the first and second portions, compositions of the first and second portions, and prior pyrolysis of hydrocarbons within the first.and second portions.

In addition, synthesis gas having a selected ratio of H2 to carbon monoxide may be obtained by controlling the temperature of the formation. In one embodiment, the temperature of an entire portion or section of the formation may be controlled to yield synthesis gas with a selected ratio. Alternatively, the temperature in or proximate to a synthesis gas production well may be controlled to yield synthesis gas with the selected ratio.

In one embodiment, synthesis gas having a selected ratio of H2 to carbon monoxide may be obtained by treating produced synthesis gas at the surface. First, the temperature of the formation may be controlled to yield synthesis gas with a ratio different than a selected ratio. For example, the formation may be maintained at a relatively high temperature to generate a synthesis gas with a relatively low H2 to carbon monoxide ratio (e.g., the ratio may approach 1 under certain conditions). Some or all of the produced synthesis gas may then be provided to a shift reactor (shift process) at the surface. Carbon monoxide reacts with water in the shift process to produce H2 and carbon dioxide.
Therefore, the shift process increases the H2 to carbon monoxide ratio. The carbon dioxide may then be separated to obtain a synthesis gas having a selected H2 to carbon monoxide ratio.

In one embodiment, produced synthesis gas 918 may be used for production of energy. In FIG. 33, treated gases 920 may be routed from treatment section 900 to energy generation unit 902 for extraction of useful energy. Energy may be extracted from the combustible gases generally by oxidizing the gases to produce heat and converting a portion of the heat into mechanical and/or electrical energy. Alternatively, energy generation unit 902 may include a fuel cell that produces electrical energy. In addition, energy generation unit 902 may include, for example, a molten carbonate fuel cell or another type of fuel cell, a turbine, a boiler firebox, or a down hole gas heater. Produced electrical energy 904 may be supplied to power grid 906.

A portion of the produced electricity 908 may be used to supply energy to electrical heating elements 910 that heat formation 912.

In one embodiment, energy generation unit 902 may be a boiler firebox. A firebox may include a small refractory-lined chamber, built wholly or partly in the wall of a kiln, for combustion of fuel. Air or oxygen 914 may be supplied to energy generation unit 902 to oxidize the produced synthesis gas. Water 916 produced by oxidation of the synthesis gas may be recycled to the formation to produce additional synthesis gas.

The produced synthesis gas may also be used as a fuel in down hole gas heaters. Down hole g s heaters, such as a flameless combustor as disclosed herein, may be configured to heat a hydrocarbon containing formation.
In this manner, a thermal conduction process may be substantially self-reliant and/or may substantially reduce or eliminate a need for electricity. Because flameless combustors may have a thermal efficiency approaching 90%, an amount of carbon dioxide released to the environment may be less than an amount of carbon dioxide released to the environment from a process using fossil-fuel generated electricity to heat the hydrocarbon containing formation.

Carbon dioxide may be produced by both pyrolysis and synthesis gas generation. Carbon dioxide may also be produced by energy generation processes and/or combustion processes. Net release of carbon dioxide to the atmosphere from an in situ conversion process for hydrocarbons may be reduced by utilizing the produced carbon dioxide and/or by storing carbon dioxide within the formation. For example, a portion of carbon dioxide produced from the formation may be utilized as a flooding agent or as a feedstock for producing chemicals.

In one embodiment, the energy generation process may produce a reduced amount of emissions by sequestering carbon dioxide produced during extraction of useful energy. For example, emissions from an energy generation process may be reduced by storing an amount of carbon dioxide within a hydrocarbon containing formation. The amount of stored carbon dioxide may be-approximately equivalent to that in an exit stream from the formation.
FIG. 33 illustrates a reduced emission energy process. Carbon dioxide 928 produced by energy generation unit 902 may be separated from fluids exiting the energy generation unit. Carbon dioxide may be separated from H2 at high temperatures by using a hot palladium film supported on porous stainless steel or a ceramic substrate, or high temperature pressure swing adsorption. The carbon dioxide may be sequestered in spent hydrocarbon containing formation 922, injected into oil producing fields 924 for enhanced oil recovery by improving mobility and production of oil in such fields, sequestered into a deep hydrocarbon containing formation 926 containing methane by adsorption and subsequent desorption of methane, or re-injected 928 into a section of the formation through a synthesis gas production well to produce carbon monoxide. Carbon dioxide leaving the energy generation unit may be sequestered in a dewatered methane reservoir. The water for synthesis gas generation may come from dewatering a methane reservoir. Additional methane can also be produced by alternating carbon dioxide and nitrogen. An example of a method for sequestering carbon dioxide is illustrated in U.S. Pat. No. 5,566,756 to Chaback et al., which is incorporated by reference as if fully set forth herein. Additional energy may be utilized by removing heat from the carbon dioxide stream leaving the energy generation unit.

In one embodiment, it may be desirable to cool a hot spent formation before sequestration of carbon dioxide.
For example, a higher quantity of carbon dioxide may be adsorbed in a coal formation at lower temperatures. In addition, cooling a formation may strengthen a formation.
The spent formation may be cooled by introducing water into the formation. The steam produced may be removed from the formation. The generated steam may be used for any desired process. For example, the steam may be provided to an adjacent portion of a furmation to heat the adjacent portion or to generate synthesis gas.

In one embodiment, a spent hydrocarbon containing formation may be mined. The mined material may in some embodiments be used for metallurgical purposes such as a fuel for generating high temperatures during production of steel. Pyrolysis of a coal containing formation may substantially increase a rank of the coal. After pyrolysis, the coal may be substantially transformed to a coal having characteristics of anthracite. A spent hydrocarbon containing formation may have a thickness of 30 m or more. Anthracite coal seams, which are typically mined for metallurgical uses, may be only about one meter in thickness.

FIG. 34 illustrates an embodiment in which fluid produced from pyrolysis may be separated into a fuel cell feed stream and fed into a fuel cell to produce electricity. The embodiment may include carbon containing formation 940 with producing well 942 configured to produce synthesis gas and heater well 944 with electric heater 946 configured to produced pyrolysis fluid 948. In one embodiment, pyrolysis fluid may include H2 and hydrocarbons with carbon numbers less than 5. Pyrolysis fluid 948 produced from heater well 944 may be fed to gas membrane separation system 950 to separate H2 and hydrocarbons with carbon numbers less than 5.
Fuel cell feed stream 952, which may be substantially composed of H2, may be fed into fuel cell 954. Air feed stream 956 may be fed into fuel cell 954. Nitrogen stream 958 may be vented from fuel cell 954. Electricity 960 produced from the fuel cell may be routed to a power grid. Electricity 962 may also be used to power electric heaters 946 in heater wells 944. Carbon dioxide 965 may be injected into formation 940.

Hydrocarbons having carbon numbers of 4, 3, and 1 typically have fairly high market values. Separation and selling of these hydrocarbons may be desirable.
Typically ethane may not be sufficiently valuable to separate and sell in some markets. Ethane may be sent as part of a fuel stream to a fuel cell or ethane may be used as a hydrocarbon fluid component of a synthesis gas generating fluid. Ethane may also be used as a feedstock to produce ethene. In some markets, there may be no market for any hydrocarbons having carbon numbers less than 5. In such a situation, all of the hydrocarbon gases produced during pyrolysis may be sent to fuel cells or be used as hydrocarbon fluid components of a synthesis gas generating fluid.

Pyrolysis fluid 964, which may be substantially composed of hydrocarbons with carbon numbers less than 5, may be injected into formation 940. When the hydrocarbons contact the formation, hydrocarbons may crack within the formation to produce methane, H2, coke, and olefins such as ethene and propylene. In one embodiment, the production of olefins may be increased by heating the temperature of the formation to the upper end of the pyrolysis temperature range and by injecting hydrocarbon fluid at a relatively high rate. In this manner, residence time of the hydrocarbons in the formation may be reduced and dehydrogenated hydrocarbons may tend to form olefins rather than cracking to form H2 and coke. Olefin production may also be increased by reducing formation pressure.

In one embodiment, electric heater 946 may be a flameless distributed combustor. At least a portion of H2 produced from the formation may be used as fuel for the flameless distributed combustor.

In addition, in some embodiments, heater well 944 may heat the formation to a synthesis gas generating temperature range. Pyrolysis fluid 964, which may be substantially composed of hydrocarbons with carbon numbers less than 5, may be injected into the formation 940. When the hydrocarbons contact the formation, the hydrocarbons may crack within the formation to produce methane, H2, and coke.

FIG. 35 depicts an embodiment of a synthesis gas generating process from hydrocarbon containing formation 976 with flameless distributed combustor 996.
Synthesis gas 980 produced from production well 978 may be fed into gas separation plant 984 where carbon dioxide 986 may be separated from synthesis gas 980.
First portion 990 of carbon dioxide may be routed to a formation for sequestration. Second portion 992 of carbon dioxide may also be injected into the formation with synthesis gas generating fluid. Portion 993 of synthesis gas 988 may be fed to heater well 994 for combustion in distributed burner 996 to produce heat for the formation. Portion 998 of synthesis gas 988 may be fed to fuel cell 1000 for the production of electricity.
Electricity 1002 may be routed to a power grid. Steam 1004 produced in the fuel cell and steam 1006 produced from'combustion in the distributed burner may be fed to the formation for generation of synthesis gas.

In one embodiment, carbon dioxide generated with pyrolysis fluids as described herein may be sequestered in a hydrocarbon containing formation. FIG. 36 illustrates in situ pyrolysis in hydrocarbon containing formation 1020. Heater well 1022 with electric heater 1024 may be disposed in formation 1020. Pyrolysis fluids 1026 may be produced from formation 1020 and fed into gas separation unit 1028 where carbon dioxide 1030 may be separated from pyrolysis fluids 1032.

Portion 1034 of carbon dioxide 1030 may be stored in formation 1036. The carbon dioxide may be sequestered in spent hydrocarbon containing formation 1038, injected into oil producing fields 1040 for enhanced oil recovery, or sequestered into coal bed 1042. Alternatively, carbon dioxide may also be re-injected 1044'into a section of formation 1020 through a synthesis gas production well to produce carbon monoxide. At least a portion of electricity 1035 may be used to power one or more electric heaters.

In one embodiment, fluid produced from pyrolysis of at least some hydrocarbons in a formation may be fed into a reformer to produce synthesis gas. The synthesis gas may be fed into a fuel cell to produce electricity. In addition, carbon dioxide generated by the fuel cell may be sequestered to reduce an amount of emissions generated by the process.

As shown in FIG. 37, heater well 1060 may be located within hydrocarbon containing formation 1062. Additional heater wells may also be located within the formation.
Heater well 1060 may include electric heater 1064.
Pyrolysis fluid 1066 produced from the formation may be fed to a reformer, such as steam reformer 1068, to produce synthesis gas 1070. A portion of the pyrolysis prodilcts may be used as fuel in the reformer. Steam reformer 1068 may include a catalyst material that promotes the reforming reaction and a burner to supply heat for the endothermic reforming reaution. A steam source may be connected to the reformer section to provide steam for the reforming reaction. The burner may operate at temperatures well above that required by the reforming reaction and well above the operating temperatures of fuel cells. As such, it may be desirable to operate the burner as a separate unit independent of the fuel cell.

Alternatively, a reformer may include multiple tubes that may be made of refractory metal alloys. Each tube may include a packed granular or pelletized material having a reforming catalyst as a surface coating. A
diameter of the tubes may vary from between about 9 cm and about 16 cm, and the heated length of the tube may normally be between about 6 m and about 12 m. A
combustion zone may be provided external to the tubes, and may be formed in the burner. A surface temperature of the tubes may be maintained by the burner at a temperature of about 900 C to ensure that the hydrocarbon fluid flowing inside the tube is properly catalyzed with steam at a temperature between about 500 C and about 700 C. A traditional tube reformer may rely upon conduction and convection heat transfer within the tube to distribute heat for reforming.
In addition, hydrocarbon fluids, such as pyrolysis fluids, may be pre-processed prior to being fed to a reformer. The reformer may be configured to transform the pyrolysis fluids into simpler reactants prior to introduction to a fuel cell. For example, pyrolysis fluids may be pre-processed in a desulfurization unit.
Subsequent to pre-processing, the pyrolysis fluids may be provided to a reformer and a shift reactor to produce a suitable fuel stock for a H2 fuelled fuel cell.
The synthesis gas produced by the reformer may include any of the components described above, such as methane. The produced synthesis gas 1070 may be fed to fuel cell 1072. A portion of electricity 1074 produced by the fuel cell may be sent to a power grid. In addition, a portion of electricity 1076 may be used to power electric heater 1064. Carbon dioxide 1078 exiting the fuel cell may be routed to sequestration area 1080.
Alternatively, in one embodiment, pyrolysis fluids 1066 produced from the formation may be fed to reformer 1068 that produces carbon dioxide stream 1082 and H2 stream 1070. For example, the reformer may include a flameless distributed combustor for a core, and a membrane. The membrane may allow only H2 to pass through the membrane resulting in separation of the H2 and carbon dioxide. The carbon dioxide may be routed to sequestration area 1080.

Synthesis gas produced from a formation may be converted to heavier condensable hydrocarbons. For example, a Fischer-Tropsch hydrocarbon synthesis process may be used for conversion of synthesis gas. A Fischer-Tropsch process may include converting synthesis gas to hydrocarbons. The process may use elevated temperatures, normal or elevated pressures, and a catalyst, such as magnetic iron oxide or a cobalt catalyst. Products produced from a Fischer-Tropsch process may include hydrocarbons having a broad molecular weight distribution and rriay include branched and unbranched paraffins.
Products from a Fischer-Tropsch process may also include considerable quantities of olefins and oxygen-containing organic compounds. An example of a Fischer-Tropsch reaction may be illustrated by the following:

(7) (n+2)CO + (2n+5)H2 H CH3 (-CH2-)n CH3 + (n+2)H20 A hydrogen to carbon monoxide ratio for synthesis gas used as a feed gas for a Fischer-Tropsch reaction may be about 2:1. In certain embodiments the ratio may range from approximately 1.8:1 to 2.2:1. Higher or lower ratios may be accommodated by certain Fischer-Tropsch systems.

FIG. 38 illustrates a flowchart of a Fischer-Tropsch process that uses synthesis gas produced from a hydrocarbon containing formation as a feed stream. Hot formation 1090 may be used to produce synthesis gas having a H2 to CO ratio of approximately 2:1. The proper ratio may be produced by operating synthesis production wells at approximately 700 C, or by blending synthesis gas produced from different sections of formation to obtain a synthesis gas having approximately a 2:1 H2 to CO ratio. Synthesis gas generating fluid 1092 may be fed into the hot formation 1090 to generate synthesis gas.
H2 and CO may be separated from the synthesis gas produced from the hot formation 1090 to form feed stream 1094. Feed stream 1094 may be sent to Fischer-Tropsch plant 1096. Feed stream 1094 may supplement or replace synthesis gas 1098 produced from catalytic methane reformer 1100.

Fischer-Tropsch plant 1096 may produce wax feed stream 1102. The Fischer-Tropsch synthesis process that produces wax feed stream 1102 is an exothermic process.

Steam 1104 may be generated during the Fischer-Tropsch process. Steam 1104 may be used as a portion of synthesis gas generating fluid 1092.

Wax feed stream 1102 produced from Fischer-Tropsch plant 1096 may be sent to hydrocracker 1106. The hydrocracker may produce product stream 1108. The product stream may include diesel, jet fuel, and/or naphtha products. Examples of methods for conversion of synthesis gas to hydrocarbons in a Fischer-Tropsch process are illustrated in U.S. Patent Nos. 4,096,163 to Chang et al., 6,085,512 to Agee et al., and 6,172,124 to Wolflick et al., which are incorporated by reference as if fully set forth herein.

FIG. 39 depicts an embodiment of in situ synthesis gas production integrated with a Shell Middle Distillates Synthesis (SMDS) Fischer-Tropsch and wax cracking process. An example of a SMDS process is illustrated in U.S. Pat. No. 4,594,468 to Minderhoud, and is incorporated by reference as if fully set forth herein.
A middle distillates hydrocarbon mixture may also be produced from produced synthesis gas using the SMDS
process as illustrated in FIG. 39. Middle distillates may designate hydrocarbon mixtures with a boiling point range that may correspond substantially with that of kerosene and gas oil fractions obtained in a conventional atmospheric distillation of crude oil material. The middle distillate boiling point range may include temperatures between about 150 C and about 360 C, with a fractions boiling point between about 200 C and about 360 C, and may be referred to as gas oil. FIG. 39 depicts synthesis gas 1120, having a H2 to carbon monoxide ratio of about 2:1, that may exit production well 1128 and may be fed into SMDS plant 1122. In certain embodiments the ratio may range from approximately 1.8:1 to 2.2:1. Products of the SMDS plant include organic liquid product 1124 and steam 1126.

Steam 1126 may be supplied to injection wells 1127. In this manner, steam may be used as a feed for synthesis gas production. Hydrocarbon vapors may in some circumstances be added to the steam.

FIG. 40 depicts an embodiment of in situ synthesis gas production integrated with a catalytic methanation process. For example, synthesis gas 1140 exiting production well 1142 may be supplied to catalytic methanation plant 1144. In some embodiments, it may be desirable for the composition of produced synthesis gas, which may be used as a feed gas for a catalytic methanation process, to have a H2 to carbon monoxide ratio of about three to one. Methane 1146 may be produced by catalytic methanation plant 1144. Steam 1148 produced by plant 1144 may be supplied to injection well 1141 for production of synthesis gas. Examples of a catalytic methanation process are illustrated in U.S.
Patent Nos. 3,992,148 to Child, 4,130,575 to Jorn et al., and 4,133,825 to Stroud et al., which are incorporated by reference as if fully set forth herein.
The synthesis gas produced may also be used as a feed for a process for production of methanol. Examples of processes for production of methanol are illustrated in U.S. Patent Nos. 4,407,973 to van Dijk et al., 4,927,857 to McShea, III et al., and 4,994,093 to Wetzel et al., which are incorporated by reference as if fully set forth herein. The produced synthesis gas may also be used as a feed gas for a process that may convert synthesis gas to gasoline and a process that may convert synthesis gas to diesel fuel. Examples of process for producing engine DEMANDES OU BREVETS VOLUMINEUX
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Claims

CLAIMS:

1. A method for treating a hydrocarbon containing formation in situ and producing a hydrocarbon fluid from the formation, which method comprises pyrolysing hydrocarbons present in the formation during the production of the hydrocarbon fluid from the formation with the application of a pressure/temperature control; wherein the pressure is at least the pressure which is calculated for a selected temperature, or the temperature is at most the temperature which is calculated for a selected pressure from the equation:

wherein P is pressure, bar absolute, T is temperature, °C, and A and B are predetermined parameters, and wherein the value of A is in the range of from 5,000 up to 60,000, B is from 10 up to 90, and P is at most 72 bar absolute to control a property which is relevant to the quantity, the composition, the quality or both of the hydrocarbon fluids produced, and wherein a heat source is applied, which is configured for heating the hydrocarbon formation substantially by conductive heating.

2. A method as claimed in claim 1, wherein the hydrocarbon containing formation comprises a kerogen or heavy hydrocarbons.

3. A method as claimed in claim 2, wherein the kerogen is coal or oil shale, and the heavy hydrocarbon is a tar sand.

4. A method as claimed in any one of claims 1 to 3, wherein at least a substantial portion of hydrocarbons present in the formation are pyrolysed by heating at a temperature below 450°C.

5. A method as claimed in claim 4, wherein at least a substantial portion of hydrocarbons present in the formation are pyrolysed by heating at a temperature in the range of from 250°C to 400°C.

6. A method as claimed in claim 5, wherein at least a substantial portion of hydrocarbons present in the formation are pyrolysed by heating at a temperature in the range of from 260°C to 375°C.

7. A method as claimed in any one of claims 1 to 6, wherein the pressure is at least 1.4 bar and wherein if the pressure is 3.52 bar and the pyrolysis takes place at a temperature up to 301.7°C a heating source is applied other than a heating source which solely provides radio frequency heating.

8. The method as claimed in claim 1, which method comprises pyrolysing hydrocarbons present in the formation during the production of the hydrocarbon fluid from the formation with the application of a pressure/temperature control, and in the presence of hydrogen at a partial pressure of hydrogen of at least 0.5 bar.

9. The method of claim 8, wherein the partial pressure of hydrogen is in the range of from 1 bar to 10 bar.

10. A method as claimed in claim 9, wherein the partial pressure of hydrogen is in the range of from bar to 7 bar.

11. A method as claimed in any one of claims 1 to 10, wherein A equals 14,000 and B equals 25.

12. A method as claimed in any one of claims 1 to 10, wherein A equals 24,146 and B equals 43.349.

13. A method as claimed in any one of claims 1 to 9, wherein A equals 30,864 and B equals 50.676.

14. A method as claimed in any one of claims 1 to 9, wherein A equals 16,947 and B equals 33.603.

15. A method as claimed in any one of claims 1 to 9, wherein A equals 57,379 and B equals 83.145.

16. A method as claimed in any one of claims 1 to 9, wherein A equals 54,928 and B equals 14.234.

17. A method as claimed in any one of claims 1 to 9, wherein A equals 38,360 and B equals 60.531.

18. A method as claimed in any one of claims 1 to 9, wherein A equals 66,131 and B equals 16.364.

19. A method as claimed in any one of claims 1 to 9, wherein A equals 28,554 and B equals 47.084.

20. A method as claimed in any one of claims 1 to 9, wherein A equals 11,118 and B equals 23.156.

21. A method as claimed in any one of claims 1 to 20, wherein subsequent to the step of treating at least part of the formation by pyrolysis at least part of the treated hydrocarbon containing formation is reacted with a synthesis gas generating fluid to produce a synthesis gas.

22. A method as claimed in claim 21, wherein the synthesis gas is converted into hydrocarbons.

23. A method as claimed in claim 19, wherein the synthesis gas is converted into paraffins by a Fischer-Tropsch hydrocarbon synthesis process and the paraffins are converted in a hydrocracker.

24. A method of producing energy comprising providing a synthesis gas which synthesis gas has been produced according to the method of claim 21, and expanding, combusting or both the synthesis gas, or using the synthesis gas in a fuel cell.

25. A system for use in the method according to any one of claims 1 to 20, the system comprising one or more heat injection wells and one or more hydrocarbon fluid production wells which are each located at one or more selected distances from said one or more heat injection wells and which are provided with pressure control devices which are adapted to maintain an elevated fluid pressure, P, in a heated part of the formation between one or more heat injection wells and one or more production wells, wherein the heat injection wells and pressure control devices are controlled such that the pressure is at least the pressure which is calculated for a selected temperature, or the temperature is at most the temperature which is calculated for a selected pressure from the equation:

wherein P is pressure, bar absolute, T is temperature, °C, and A and B are predetermined parameters, and wherein the value of A is in the range of from 5,000 up to 60,000, B is from 10 up to 90, and P is at most 72 bar absolute to control a property which is relevant to the quantity, the composition or the quality of the hydrocarbon fluids produced.

26. The system of claim 25, wherein each hydrocarbon fluid production well is provided with a pressure control device which maintains the pressure within at least part of the wellbore of the production well at a pre-set value which is determined in relation to an assessed temperature in the pyrolysis zone from which in use pyrolysed hydrocarbon fluids flow through the formation into the wellbore of the production well.

27. The system of claim 25, wherein a plurality of heat injection wells are located at one or more selected distances and in a substantially triangular pattern around each production well.

28. The system of claim 25, wherein at least one of the heat injection and production wells is drilled substantially parallel to the upper and lower boundaries of the hydrocarbon bearing formation.

29. The system of claim 25, wherein at least one of the heat injection and production wells is drilled substantially orthogonal to the upper and lower boundaries of the hydrocarbon bearing formation.

30. The system of claim 25, wherein at least one of the heat injection wells comprises:

an oxidizing fluid supply conduit to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least a portion of the hydrocarbons in the formation in the vicinity of the wellbore zone during use such that heat is generated at the reaction zone; and a combustion gases exhaust conduit for venting combustion gases from the reaction zone to the earth surface to allow heat to transfer substantially by conduction from the reaction zone to a selected section of the formation during use.

31. The system of claim 30, wherein the oxidant injection and combustion gases exhaust conduits are equipped with pressure regulation devices which control the pressure in the heater well such that at least a substantial part of the combustion gases generated at the reaction zone are vented to the earth surface through the combustion gases exhaust conduit.

32. The system of claim 30 or 31, wherein the oxidant injection conduit and the combustion gases exhaust conduit extend co-axially to each other from a wellhead of the heater well into the hydrocarbon bearing formation, the oxidant injection conduit protrudes from the lower end of the combustion gases exhaust conduit through a reaction zone traversing the hydrocarbon bearing formation and the protruding lower part of the oxidant injection conduit is equipped with an array of oxidant injection orifices for injecting oxidant into an annular space between the oxidant injection conduit and the reaction zone.

33. The system of any one of claims 25 to 32, wherein at least one heater well comprises an electric heater.

34. The system of claim 33, wherein the electric heater comprises:

a mineral insulated cable disposed within an uncased section of the wellbore of the heater well which extend through the hydrocarbon containing formation, wherein the mineral insulated cable is configured to provide radiant heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the mineral insulated cable to a section of the formation during use.

35. The system of claim 34, wherein the mineral insulated cable comprises a conductor comprising a copper-nickel alloy, which conductor is disposed in an insulating mineral material which comprises magnesium oxide, other mineral grain particles or a combination thereof which are disposed in a sheath comprising a corrosion-resistant material.

36. The system of claim 33, wherein the electric heater comprises a first electrical conductor disposed in a first conduit which is disposed within the heater well.

37. The system of claim 36, further comprising a sliding electrical connector coupled to the first conductor, the first conduit or both and wherein a fluid is disposed within the first conduit, wherein the fluid is configured to maintain a pressure within the first conduit to substantially prevent deformation of the first conduit during use.

38. The system of claim 36, further comprising a tube disposed within an annular opening external to the first conduit, wherein the tube is configured to remove vapour produced from at least the heated portion of the formation such that a pressure balance is maintained between the first conduit and the opening to substantially prevent deformation of the first conduit during use.

39. The system of claim 33, wherein the electric heater comprises at least one elongate electrical conductor member, which is arranged in an at least partly uncased section of the heater well.

40. The system of claim 39, wherein a fluid supply conduit is disposed within the heater well for injecting a cleaning fluid at the surface of the electrical conductor member to inhibit deposition of combustion products on or proximate to at least the one elongate electrical conductor member during use.

41. The system of claim 40, wherein the cleaning fluid is air.

42. The system of claim 40 or 41, wherein the elongate electrical conductor member is supported by the fluid supply conduit by a series of insulated centralizers and the conduit comprises a series of fluid injection orifices adjacent to the elongate electrical conductor member.

43. The system of any one of claims 25 to 42, wherein the electrical heaters, other heaters or both in at least one of the heater wells are configured to generate during use an accumulated radiant heat of between 0.5 and 1.5 KW
per meter length of the relevant heater well.

44. A pyrolysis product obtainable by the process as claimed in any one of claims 1 to 20, the product comprising less than 10% by weight of olefins and having an average carbon number less than 35, wherein the product comprises condensable hydrocarbons having an elemental nitrogen content less than 1% by weight of the condensable hydrocarbons, an aromatics content greater than 20% by weight of the condensable hydrocarbons or both.

45. The pyrolysis product of claim 44, comprising condensable hydrocarbons having an elemental nitrogen content less than 1%; an elemental oxygen content less than 1%; and an elemental sulfur content less than 1%.

46. The pyrolysis product of claim 44, comprising condensable hydrocarbons having an elemental nitrogen content less than 1% by weight on a dry basis; an elemental oxygen content less than 1% by weight on a dry basis; and an elemental sulfur content less than 1% by weight on a dry basis.

47. The pyrolysis product of claim 44, having an average carbon number less than 30.

48. The pyrolysis product of claim 47, having an average carbon number less than 25.

49. The pyrolysis product of claim 44, comprising a non-condensable component comprising hydrocarbons having carbon numbers of less than 5; and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4 to methane is greater than 1.

50. The pyrolysis product of claim 44, having an ammonia-containing component, wherein a weight percentage of the ammonia-containing component in the product is greater than 0.5%.

51. The pyrolysis product of claim 49, comprising a condensable component, wherein an olefin content of the condensable component is less than 9% by weight of the condensable component.

52. The pyrolysis product of claim 44, comprising a hydrocarbon component, wherein less than 5 weight % of compounds within the hydrocarbon component have a carbon number greater than 20.

53. The pyrolysis product of claim 51, wherein an aromatic content of the condensable component is more than 30% by weight of the condensable component.

54. The pyrolysis product of claim 44, comprising:
hydrocarbons comprising 1, 2, 3, or 4 carbon atoms, or mixtures thereof, and wherein the weight ratio of C2-4 to methane is greater than 1, wherein C2-4 is defined as the sum of the hydrocarbons containing 2, 3, and 4 carbon atoms; and a water content greater than 0.1% by weight;

a hydrogen sulphide content of less than 1.5% by weight;

a H2 content less than 20% by weight;

an olefin content less than 10% by weight; and a condensable component, wherein an aromatic content of the condensable component is more than 30% by weight.

55. The pyrolysis product of claim 44, comprising:

a hydrocarbon component, wherein less than 5% of compounds within the hydrocarbon component have a carbon number greater than 20;

a water content greater than 0.1% by weight;
a hydrogen sulphide content less than 1.5% by weight;

a H2 content less than 20% by weight;

an olefin content less than 10% by weight; and a condensable component, wherein an aromatic content of the condensable component is more than 30% by weight.

56. The pyrolysis product of claim 44, comprising a condensable component having an olefin content between 0.1% and 5% by weight of condensable component; and a naphthalene content of the hydrocarbon liquid from 0% to 0.1% by weight of the condensable component.

57. The pyrolysis product of claim 44, comprising a condensable fluid which comprises a weight percentage of olefins in a range of 0.1% to 2%; and a weight percentage of tri-aromatics of less than 2%.

58. The pyrolysis product of claim 44, comprising:
a weight percentage of H2 greater than 10%;

a weight percentage of ammonia greater than 0.5%;
and a weight ratio of hydrocarbons having greater than 2 carbon atoms to methane is greater than 0.4.

59. The pyrolysis product of any one of claims 44 to 58, wherein the pyrolysis product is obtained by the method as claimed in any one of claims 1 to 20.