U.S. patent application number 12/424887 was filed with the patent office on 2009-10-22 for methods for generation of subsurface heat for treatment of a hydrocarbon containing formation.
Invention is credited to Jingyu CUI, Mahendra Ladharam Joshi, Stanley Nemec Milam, Michael Anthony Reynolds, Scott Lee Wellington.
Application Number | 20090260811 12/424887 |
Document ID | / |
Family ID | 41016918 |
Filed Date | 2009-10-22 |
United States Patent
Application |
20090260811 |
Kind Code |
A1 |
CUI; Jingyu ; et
al. |
October 22, 2009 |
METHODS FOR GENERATION OF SUBSURFACE HEAT FOR TREATMENT OF A
HYDROCARBON CONTAINING FORMATION
Abstract
Methods of generating subsurface heat for treatment of a
hydrocarbon containing formation are described herein. Steam is
provided to at least a portion of a hydrocarbon containing
formation from a plurality of substantially horizontal steam
injection wells. A mixture comprising hydrogen sulfide and an
oxidant is combusted in one or more flameless distributed
combustors positioned in one or more substantially vertical
wellbores to generate heat. At least one of the substantially
vertical wellbores is within ten meters of an end of at least one
of the substantially horizontal steam injection wells, and at least
a portion of the generated heat is transferred to a portion of the
hydrocarbon containing formation located between at least one of
the substantially horizontal steam injection wells and at least one
of the substantially vertical heater wells to mobilize formation
fluids for recovery.
Inventors: |
CUI; Jingyu; (Katy, TX)
; Joshi; Mahendra Ladharam; (Katy, TX) ;
Wellington; Scott Lee; (Bellaire, TX) ; Reynolds;
Michael Anthony; (Katy, TX) ; Milam; Stanley
Nemec; (Houston, TX) |
Correspondence
Address: |
SHELL OIL COMPANY
P O BOX 2463
HOUSTON
TX
772522463
US
|
Family ID: |
41016918 |
Appl. No.: |
12/424887 |
Filed: |
April 16, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61046172 |
Apr 18, 2008 |
|
|
|
Current U.S.
Class: |
166/272.3 |
Current CPC
Class: |
E21B 36/02 20130101;
E21B 43/2406 20130101; E21B 43/305 20130101; E21B 43/243 20130101;
E21B 43/2408 20130101 |
Class at
Publication: |
166/272.3 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 36/02 20060101 E21B036/02; E21B 36/00 20060101
E21B036/00; E21B 43/20 20060101 E21B043/20 |
Claims
1. A method of treating a hydrocarbon containing formation,
comprising: providing steam to at least a portion of a hydrocarbon
containing formation from a plurality of substantially horizontal
steam injection wells; combusting at least a portion of a mixture
comprising hydrogen sulfide and oxidant in one or more flameless
distributed combustors positioned in one or more substantially
vertical wellbores to generate heat, wherein at least one of the
substantially vertical wellbores is within ten meters of an end of
at least one of the substantially horizontal steam injection wells;
transferring at least a portion of the generated heat to a portion
of the hydrocarbon containing formation located between at least
one of the substantially horizontal steam injection wells and at
least one of the substantially vertical heater wells; and
mobilizing at least a portion of formation fluids in the heated
portion of the hydrocarbon containing formation.
2. The method of claim 1, further comprising producing formation
fluids from a volume between at least one of the substantially
vertical heater wells and at least one of the substantially
horizontal steam injection wells.
3. The method of claim 1, wherein the steam transfers heat to at
least a portion of the hydrocarbon containing formation.
4. The method of claim 1, wherein at least a portion of the steam
drives at least a portion of the formation fluids towards one or
more production wells.
5. The method of claim 1, wherein combustion produces combustion
by-products, and further comprising the step of transferring at
least a portion of the combustion by-products into the formation
such that at least a portion of the combustion by-products provide
a driving force for mobilization of at least a portion of the
formation fluids.
6. The method of claim 5, wherein at least a portion of the steam
provides a driving force for mobilization of at least a portion of
the formation fluids.
7. The method of claim 1, wherein combustion produces combustion
by-products comprising sulfur oxides, further comprising the step
of mixing at least a portion of the combustion by-products with
water in the hydrocarbon formation to generate a heat of solution
generating a heat of solution.
8. The method of claim 1, wherein combustion produces combustion
by-products comprising sulfur dioxide, further comprising the step
of mixing at least a portion of the combustion by-products with at
least a portion of formation fluids to form a mixture, and
mobilizing at least a portion of the mixture.
9. The method of claim 1, wherein combustion produces a combustion
by-products stream and the method further comprising the steps of
transferring at least a portion of the generated heat to a least a
portion formation fluids in the hydrocarbon containing formation;
solvating at least a portion of the heated formation fluids with at
least a portion of the combustion by-products stream; and
mobilizing at least a portion of heated and solvated formation
fluids.
10. The method of claim 1, wherein combusting at least a portion of
the mixture comprises selecting a ratio of hydrogen sulfide to the
oxidant for combustion such that during combustion a selected
amount of hydrogen sulfide, sulfur trioxide, sulfur dioxide, or
mixtures thereof is formed.
11. The method of claim 10, wherein combusting at least a portion
of the mixture comprises selecting a ratio of hydrogen sulfide to
the oxidant for combustion such that combustion generates
substantially sulfur trioxide.
12. The method of claim 10 wherein combusting at least a portion of
the mixture comprises selecting a ratio of hydrogen sulfide to the
oxidant for combustion such that combustion generates substantially
sulfur dioxide and hydrogen sulfide.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from U.S. Provisional
Application Ser. No. 61/046,172 filed Apr. 18, 2008, which is
hereby incorporated by reference in its entirety.
FIELD OF THE INVENTION
[0002] The present invention relates to methods of treating of a
hydrocarbon containing formation.
DESCRIPTION OF RELATED ART
[0003] Hydrocarbons obtained from subterranean formations are often
used as energy resources, as feedstocks, and as consumer products.
Concerns over depletion of available hydrocarbon resources have led
to development of processes for more efficient recovery, processing
and/or use of available hydrocarbon resources.
[0004] Hydrocarbon formations may be treated in various ways to
produce formation fluids. For example, application of heat, gases,
and/or liquids to hydrocarbon formations to mobilize and/or produce
formation fluids has been used to more efficiently recover
hydrocarbons from hydrocarbon formations. Hydrocarbon formations
containing heavy hydrocarbons--for example, tar sands or oil shale
formations--may be heated using heat treatment methods to more
efficiently recover hydrocarbons from the heavy hydrocarbon
containing formations. Such processes include in situ heat
treatment systems, combustion fronts, and drive processes.
Typically used hydrocarbon recovery drive processes include, but
are not limited to, cyclic steam injection, steam assisted gravity
drainage (SAGD), solvent injection, vapor solvent and SAGD, and
carbon dioxide injection.
[0005] Heaters have been used in hydrocarbon recovery drive
processes to create high permeability zones (or injection zones) in
hydrocarbon formations. Heaters may be used to create a
mobilization geometry or production network in the hydrocarbon
formation to allow fluids to flow through the formation during the
drive process. For example, heaters may be used: to create drainage
paths between the injection wells and production wells for the
drive process; to preheat the hydrocarbon formation to mobilize
fluids in the formation so that fluids and/or gases may be injected
into the formation; and to provide heat to the fluids and/or gases
used in the drive process within the hydrocarbon formation. Often,
the amount of heat provided by such heaters is small relative to
the amount of heat input from the drive process.
[0006] Combustion of fossil fuel has been used to heat a formation,
for example, by direct injection of hot fossil fuel combustion
gases in the formation, by combustion of fossil fuels in the
formation (e.g. in a combustion front), by heat transfer from the
hot fossil fuel combustion gases to another heat transfer agent
such as steam, or by use in heaters located in the hydrocarbon
formation. Combustion of fossil fuels to heat a formation may take
place in the formation, in a well, and/or near the surface.
Combustion of fossil fuel generates carbon dioxide, an undesirable
greenhouse gas, as a combustion by-product.
[0007] Combustion of sulfur compounds has also been used to heat a
hydrocarbon formation, where the sulfur containing combustion
products may act as a drive fluid for the more efficient production
of hydrocarbons from the hydrocarbon formation. U.S. Pat. No.
4,379,489 to Rollmann describes a method for recovery of heavy oil
from a subterranean reservoir that includes burning liquid sulfur
in an oxygen-containing gas underground to form sulfur dioxide. The
sulfur dioxide may act as a drive fluid for the recovery of oil or
it may react with limestone in the formation to form carbon
dioxide, an alternate drive fluid. The pressure of the
oxygen-containing gas is maintained at a pressure sufficient to
keep the sulfur dioxide in the liquid state.
[0008] An efficient, cost effective method for treating a
hydrocarbon formation to more efficiently recover hydrocarbons from
the hydrocarbon formation without the production of large
quantities of carbon dioxide is desirable.
SUMMARY OF THE INVENTION
[0009] The present invention is directed to a method of treating a
hydrocarbon formation comprising providing steam to at least a
portion of a hydrocarbon containing formation from a plurality of
substantially horizontal steam injection wells; combusting at least
a portion of a mixture comprising hydrogen sulfide and an oxidant
in one or more flameless distributed combustors positioned in one
or more substantially vertical wellbores to generate heat, wherein
at least one of the substantially vertical wellbores is within ten
meters of an end of at least one of the substantially horizontal
steam injection wells; transferring at least a portion of the
generated heat to a portion of the hydrocarbon containing formation
located between at least one of the substantially horizontal steam
injection wells and at least one of the substantially vertical
heater wells; and mobilizing at least a portion of formation fluids
in the heated portion of the hydrocarbon containing formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] 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:
[0011] FIG. 1 depicts a representation of a steam drive
process.
[0012] FIG. 2 depicts a schematic representation of an embodiment
of treatment of formation fluids produced from a hydrocarbon
formation.
[0013] FIG. 3 depicts a cross-sectional representation of a portion
of an embodiment of a hydrogen sulfide fueled flameless distributed
combustor positioned in a vertical wellbore.
[0014] FIG. 4 depicts a cross-sectional representation of a portion
of an embodiment of a hydrogen sulfide fueled flameless distributed
combustor with two fuel conduits.
[0015] FIG. 5 depicts a cross-sectional representation of a portion
of an embodiment of a hydrogen sulfide fueled flameless distributed
combustor with three fuel conduits.
[0016] FIG. 6 depicts a cross-sectional representation of a portion
of an embodiment of a hydrogen sulfide fueled flameless distributed
combustor with an ignition source positioned in a vertical
wellbore.
[0017] FIG. 7 depicts a cross-sectional representation of a portion
of an embodiment of a hydrogen sulfide fueled burner positioned in
a horizontal wellbore.
[0018] FIG. 8 depicts a representation of an embodiment for
producing hydrocarbons using a vertical hydrogen sulfide fueled
heater in combination with a horizontal steam injection well.
[0019] While the invention is susceptible to various modifications
and alternative forms, specific embodiments thereof are shown by
way of example in the drawings. The drawings may not be to scale.
It should be understood, however, that the drawings 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
[0020] The present invention is directed to providing subsurface
heat to a hydrocarbon formation where the heat is generated by 1)
combusting at least a portion of a mixture comprising hydrogen
sulfide and an oxidant in one or more flameless distributed
combustors positioned in one or more substantially vertical
wellbores; and 2) providing steam in one or more substantially
horizontal steam injection wells. The heat provided to the
hydrocarbon formation mobilizes at least a portion of formation
fluids in the heated portion of the hydrocarbon containing
formation. Since the fuel stream is sulfur based, production of
carbon dioxide is avoided upon combustion of the sulfide components
of the fuel stream, reducing the overall production of carbon
dioxide of the heating process relative to processes that utilize a
fuel stream comprised mostly of hydrocarbons.
[0021] The process of the present invention provides heat
efficiently to the hydrocarbon formation since heat from combustion
of a fuel stream comprising hydrogen sulfide and heat from steam
are provided to the hydrocarbon formation. The heat provided to the
hydrocarbon formation from the combustion of the fuel stream
comprising hydrogen sulfide may enhance the mobilization of
formation fluids by the steam injection due to the relative
positioning of the vertical wellbores from which the heat of
combustion is provided relative to the steam injection wellbores.
The substantially horizontal steam injection wells and the
substantially vertical wellbores are positioned to provide heat
generated by the combustion of the mixture of hydrogen sulfide and
oxidant to the hydrocarbon formation at a portion of the
hydrocarbon containing formation located between at least one of
the substantially horizontal steam injection wells and at least one
of the substantially vertical wellbores. The heat provided to the
heated portion of the hydrocarbon formation mobilizes the formation
fluids in the heated portion of the hydrocarbon formation, and may
increase the amount of formation fluids recovered and produced from
the hydrocarbon formation from a production well.
[0022] The process of oxidizing hydrogen sulfide through a
combustion process to a produce sulfuric acid may have a heat value
similar to methane combustion. For example, using data from "The
Chemical Thermodynamics of Organic Compounds" by Stull et al.;
Kreiger Publishing Company, Malabar Fla., 1987, pp. 220, 229, 230,
233 and 234, the enthalpies of reaction for the combustion of
methane and hydrogen sulfide can be calculated. Combustion of
methane produces carbon dioxide as a by-product, as shown by the
following reaction:
CH.sub.4+2O.sub.2.fwdarw.CO.sub.2+2H.sub.2O
(.DELTA.H.sub.r.times.n=-191.2 kcal/mol at 600.degree. K.).
In contrast, oxidation (combustion) of hydrogen sulfide to form
sulfuric acid has a calculated reaction enthalpy as shown in the
following reaction:
H.sub.2S+2O.sub.2.fwdarw.H.sub.2SO.sub.4
(.DELTA.H.sub.r.times.n=-185.4 kcal/mol at 600.degree. K.).
More heat may be generated upon mixing the sulfuric acid in water
by the heat of solution of sulfuric acid in water as shown
below:
H.sub.2SO.sub.4+H.sub.2O.fwdarw.50 wt % H.sub.2SO.sub.4
(.DELTA.H.sub.dil=-14.2 kcal/mol at 298.degree. K.).
[0023] The total amount of heat content produced from the
combustion of hydrogen sulfide and the dissolution of the sulfuric
acid may range from -185 kcal/mol to -206 kcal/mol depending on the
amount of water used to produce the sulfuric acid. Combustion of
hydrogen sulfide as a fuel instead of methane in accordance with
the process of the present invention, therefore, provides heat to a
hydrocarbon formation in an amount comparable to the combustion of
methane while producing no carbon dioxide. Furthermore, the use of
fuels containing hydrogen sulfide in the process of the present
invention provides a method to dispose of waste hydrogen sulfide
from other processes (for example, sour gas and/or hydrotreating
effluent streams) without creating elemental sulfur.
[0024] Terms used herein are defined as follows.
[0025] "API gravity" refers to API gravity at 15.5.degree. C.
(60.degree. F.). API gravity is as determined by ASTM Method D6822
or ASTM Method D1298.
[0026] "ASTM" refers to American Standard Testing and
Materials.
[0027] A "formation" includes one or more hydrocarbon containing
layers, one or more non-hydrocarbon layers, an overburden, and/or
an underburden. "Hydrocarbon layers" refer to layers in the
formation that contain hydrocarbons. The hydrocarbon layers may
contain non-hydrocarbon material and hydrocarbon material. The
"overburden" and/or the "underburden" include one or more different
types of hydrocarbon impermeable materials. In some cases, the
overburden and/or the underburden may be somewhat permeable to
hydrocarbon materials.
[0028] "Formation fluids" refer to fluids present in a formation
and may include pyrolysis fluid, synthesis gas, mobilized
hydrocarbons, and water (steam). Formation fluids may include
hydrocarbon fluids as well as non-hydrocarbon fluids. The term
"mobilized fluid" refers to fluids in a hydrocarbon containing
formation that are able to flow as a result of treatment of the
formation. "Produced fluids" refer to fluids removed from the
formation.
[0029] A "heater" is any system or heat source for generating heat
in a well or a near wellbore region. Heaters may be, but are not
limited to, electric heaters, burners, combustors that react with
material in or produced from a formation, and/or combinations
thereof. "Flameless distributed combustor" refers to a
substantially flameless heater where an oxidant stream and a fuel
stream are mixed together over at least a portion of the
distributed length of the heater at or above an auto-ignition
temperature of the mixture.
[0030] "Heavy hydrocarbons" are viscous hydrocarbon fluids. Heavy
hydrocarbons may include highly viscous hydrocarbon fluids such as
heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include
carbon and hydrogen, as well as smaller concentrations of compounds
containing sulfur, oxygen, and nitrogen. Additional elements (for
example, nickel, iron, vanadium, or mixtures thereof) may also be
present in heavy hydrocarbons. 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 at
least 100 centipoise at 15.degree. C. Heavy hydrocarbons may
include aromatics or other complex ring hydrocarbons.
[0031] "Hydrocarbons" are generally defined as molecules formed
primarily by carbon and hydrogen atoms.
[0032] Hydrocarbons as used herein may also include metallic
elements and/or other compounds that contain, but are not limited
to, halogens, nitrogen, oxygen, and/or sulfur. Hydrocarbon
compounds that contain sulfur are referred to as "organosulfur
compounds." Hydrocarbons may be, but are not limited to, kerogen,
bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites.
Hydrocarbons may be located in or adjacent to mineral matrices in
the earth. Matrices may include, but are not limited to,
sedimentary rock, sands, silicilytes, carbonates, diatomites, and
other porous media. "Hydrocarbon fluids" are fluids that include
hydrocarbons. Hydrocarbon fluids may include, entrain, or be
entrained in non-hydrocarbon fluids such as hydrogen, nitrogen,
carbon monoxide, carbon dioxide, hydrogen sulfide, sulfur oxides,
carbonyl sulfide, nitrogen oxide, water, ammonia, or mixtures
thereof.
[0033] "Oxidant" refers to compounds suitable to support
combustion. Examples of oxidants include air, oxygen, and/or
enriched air. "Enriched air" refers to air having a larger mole
fraction of oxygen than air in the atmosphere. Air is typically
enriched to increase combustion-supporting ability of the air.
[0034] "SAGD" is steam assisted gravity drainage.
[0035] "Tar" is a viscous hydrocarbon that generally has a
viscosity greater than about 10,000 centipoise at 15.degree. C. The
specific gravity of tar generally is greater than 1.000. Tar may
have an API gravity less than 10.degree..
[0036] "Tar sands formation" refers to a formation in which
hydrocarbons are predominantly present in the form of heavy
hydrocarbons and/or tar entrained in a mineral grain framework or
other host lithology (for example, sand or carbonate). Examples of
tar sands formations include formations such as the Athabasca
formation, the Grosmont formation, and the Peace River formation,
all three in Alberta, Canada; and the Faja formation in the Orinoco
belt in Venezuela.
[0037] "Water" refers to the liquid and vapor phases of water. For
example, water, steam, super-heated steam.
[0038] In the process of the present invention, steam is provided
to at least a portion of a hydrocarbon formation. The hydrocarbon
formation includes hydrocarbon material and may include
non-hydrocarbon materials, where the hydrocarbon materials may be
recovered from the hydrocarbon formation. The hydrocarbon formation
may include an overburden and an underburden that are impermeable
or only slightly permeable to hydrocarbons.
[0039] Steam is provided to the hydrocarbon formation to enable an
increased amount of hydrocarbon materials to be recovered from the
hydrocarbon formation. The steam provided to the hydrocarbon
formation may heat the hydrocarbon formation and thereby mobilize
formation fluids including hydrocarbon materials, where the
mobilized formation fluids may be recovered and produced from the
hydrocarbon formation by a production well. The steam may also
displace formation fluids in the hydrocarbon formation and drive
the formation fluids to a production well so the formation fluids
may be recovered and produced from the production well.
[0040] In an embodiment of the process of the invention, the steam
may be provided to the hydrocarbon formation in a drive process to
treat a hydrocarbon formation. Such drive processes include, but
are not limited to cyclic steam injection, SAGD, solvent injection,
or a vapor solvent and SAGD process. The process of the invention
may also be used to preheat a hydrocarbon formation for a drive
process, or may be used to provide heat during or after a drive
process.
[0041] FIG. 1 depicts a representation of a steam drive process in
which the process of the present invention may be utilized. Steam
100 enters injection well 102. Injection well 102 may include
openings 104 to allow steam 100 to flow and/or be pressurized into
hydrocarbon layer 106. Steam 100 provides heat to formation fluids
in the hydrocarbon layer 106. Heating the formation fluids may
mobilize the formation fluids to promote drainage of the formation
fluids towards production well 108 positioned below injection well
102. Formation fluid 110 is produced from production well 108 and
transported to one or more processing facilities.
[0042] The steam is provided to the hydrocarbon formation from a
plurality--at least two--of substantially horizontal steam
injection wells. The steam injection wells are preferably located
in a position relative to one or more production wells such that
formation fluids mobilized and/or driven by injection of the steam
in the steam injection wells are mobilized and/or driven towards
the production well so that the formation fluids may be recovered
and produced by the production well. Most preferably, the steam
injection wells are located in a position relative to the one or
more production wells and the one or more substantially vertical
wellbores in which the mixture comprising hydrogen sulfide and an
oxidant are combusted to optimize the amount of formation fluids
recovered from the hydrocarbon formation. As used herein, a
"substantially horizontal" well or wellbore refers to a well or
wellbore that has an inclination of 30.degree. or less, or
15.degree. or less, or 10.degree. or less in the hydrocarbon
formation at or near, for example within 20 meters, of one or more
of the substantially vertical wells or wellbores, and preferably at
the terminus of the substantially horizontal well or wellbore. A
substantially horizontal well or wellbore may have portions of the
well or wellbore that have an inclination of greater than
30.degree. C., and may approach or be vertical. For example, a
substantially horizontal well or wellbore may have a substantially
vertical portion at or near the surface of a hydrocarbon formation,
but has a portion that is substantially horizontal within the
hydrocarbon formation near a substantially vertical wellbore in
which the mixture comprising hydrogen sulfide and an oxidant are
combusted.
[0043] The steam provided to the hydrocarbon containing formation
preferably has a temperature greater than the temperature of the
hydrocarbon containing formation to which the steam is provided.
The steam may be provided to the hydrocarbon containing formation
through the substantially horizontal injection wells at a
temperature of from 100.degree. C. to 500.degree. C., or from
110.degree. C. to 290.degree. C., and at pressures ranging from 1
MPa to 15 MPa.
[0044] Water or steam may be heated prior to being provided to the
hydrocarbon formation through the steam injection wells. The
water/steam may be heated at the surface of the hydrocarbon
formation prior to provided to the steam injection wells for
injection into the hydrocarbon formation, and/or it may be heated
subsurface in one or more wellbores by one or more heaters provided
in the one or more wellbores.
[0045] The water/steam may be heated at the surface of the
hydrocarbon formation by transferring heat from combustion of a
fuel stream and an oxidant with the water/steam. The fuel stream
may be a hydrocarbon containing fuel, for example, natural gas,
and/or the fuel stream may be a fuel stream comprising hydrogen
sulfide. The oxidant may be air, compressed air, oxygen-enriched
air, or oxygen gas. The fuel stream and the oxidant may be
combusted in a conventional combustor reactor, and the heat of
combustion may be transferred to the water/steam by heat exchange
between the combustion by-product gases and the water/steam.
[0046] The water/steam may be heated in the one or more wellbores
subsurface prior to being provided to the hydrocarbon formation.
One or more heaters may be provided within the one or more
wellbores for heating the water/steam in the one or more wellbores
prior to providing the steam to the hydrocarbon formation.
Subsurface heating of the water/steam permits efficient
transmission of heat from the steam to the hydrocarbon formation by
enabling the steam to be heated near the point at which the steam
is provided to the hydrocarbon formation. In an embodiment, a fuel
stream and an oxidant stream are combusted in the one or more
heaters in the one or more steam injection wellbores and the heat
of combustion is transferred to the water/steam in the wellbore
prior to providing the steam to the hydrocarbon formation. The fuel
stream may be a hydrocarbon containing fuel, for example, natural
gas, and/or the fuel stream may comprise hydrogen sulfide. The
oxidant may be air, compressed air, oxygen-enriched air, and/or
oxygen gas. The heaters for providing heat to the water/steam in
the wellbore(s) may be flameless distributed combustors or
burners.
[0047] In some embodiments, one or more heaters may be positioned
in an inner portion of a wellbore of one or more substantially
horizontal steam injection wells, and the steam may flow through an
outer portion of the wellbore in position so that heat may be
transferred from the heater to the steam. The heater may be
positioned in an inner conduit coupled to an outer conduit. The two
conduits may be placed in the wellbore. The conduits may be side by
side. It should be understood that any number and/or configuration
contemplated configuration of conduits may be used as contemplated
or desired.
[0048] Fuel may be provided to one or more fuel conduits in the one
or more heaters in the one or more substantially horizontal steam
injection wells. The fuel stream for the heaters and an oxidant may
be provided to one or more fuel conduits in at least one of the
heaters for combustion in the heaters. The fuel conduits may be
arranged such that at least a portion of the fuel is introduced to
an upstream portion of at least one of the heaters and at least a
portion of the fuel stream is introduced to a downstream portion of
at least one of the heaters. The fuel may be provided to one or
more fuel conduits in at least one of the heaters, where at least
one of the conduits is adjustable such that at least a portion of
the fuel is delivered to a first portion of the heater and then to
a second portion of the heater downstream of the first portion.
[0049] The steam is provided to the hydrocarbon formation from the
plurality of substantially horizontal steam injection wells. The
steam may be provided to the hydrocarbon formation under pressure
so that the steam is injected into the hydrocarbon formation. The
injected steam may mobilize formation fluids by driving the
formation fluids. Preferably the steam provided to the hydrocarbon
formation is provided to the hydrocarbon formation at a temperature
higher than the temperature of the hydrocarbon formation so that
heat may be transferred from the steam to the hydrocarbon
formation. Heat provided from the steam to the hydrocarbon
formation may mobilize formation fluids in the hydrocarbon
formation.
[0050] Providing the steam to the hydrocarbon formation through the
plurality of substantially horizontal steam injection wells into
the hydrocarbon containing formation may move or drive the
formation fluids to a production well. The steam may contact the
formation fluids and mix with a portion of the formation fluids,
solvate a portion of the formation fluids and/or dissolve a portion
of the hydrocarbons. Contacting of the steam with the formation
fluids may lower the viscosity the formation fluids and promote
movement of the formation fluids towards one or more production
wells.
[0051] In the process of the present invention, a mixture
comprising hydrogen sulfide and an oxidant is combusted in one or
more flameless distributed combustors positioned in one or more
substantially vertical wellbores to generate heat. One or more of
the substantially vertical wellbores is/are positioned within ten
meters of an end of at least one of the substantially horizontal
steam injection wells. Most preferably, the substantially vertical
wellbores in which the mixture is combusted are located in position
relative to the one or more production wells and the one or more
substantially horizontal steam injection wells to optimize the
amount of formation fluids recovered from the hydrocarbon
formation. As used herein, a "substantially vertical" well or
wellbore refers to a well or wellbore that has an inclination of
60.degree. or more, or 75.degree. or more, or 80.degree. or more in
the hydrocarbon formation at or near, for example within 20 meters
or within 10 meters, of one or more of the end of one or more
substantially horizontal steam injection wells or wellbores. A
substantially vertical well or wellbore may have portions of the
well or wellbore that have an inclination of less than 60.degree.
C., and may approach or be horizontal in some portions of the well
or wellbore.
[0052] The hydrogen sulfide used in the process of the present
invention may be provided in a fuel stream including from 1% to
100%, from 3% to 90%, from 10% to 80%, or from 20% to 50% of
hydrogen sulfide by volume, or may include at least 10%, or at
least 30%, or at least 40%, or at least 50%, or at least 60%, or at
least 70% hydrogen sulfide by volume. Hydrogen sulfide content in a
stream may be measured using ASTM Method D2420. The fuel stream
comprising hydrogen sulfide may include hydrocarbons (for example,
methane, and ethane), hydrogen, carbon dioxide, or mixtures
thereof. In some embodiments, the fuel may include organosulfur
compounds. Examples of organosulfur compounds include, but are not
limited to, methyl thiol, thiophene, thiophene compounds, carbon
disulfide, carbonyl sulfide, or mixtures thereof. The use of fuels
containing hydrogen sulfide and/or organosulfur compounds may allow
from 0.3 moles to 1 mole of methane to be conserved per mole of
atomic sulfur in the fuel.
[0053] A fuel stream comprising hydrogen sulfide may produced from
a hydrocarbon containing formation. FIG. 2 depicts a schematic
representation of treatment of formation fluids produced from a
hydrocarbon formation. Produced formation fluid 110 enters fluid
separation unit 112 and is separated into liquid stream 114, gas
stream 116, and aqueous stream 118. Produced formation fluid 110
may obtained from a hydrocarbon formation that is primarily a gas
reservoir or from a hydrocarbon formation that is primarily a
liquid hydrocarbon reservoir. Liquid stream 114 may be transported
to other processing units and/or storage units. Gas stream 116 may
include, but is not limited to, hydrocarbons, carbonyl sulfide,
hydrogen sulfide, sulfur oxides, organosulfur compounds, hydrogen,
carbon dioxide, or mixtures thereof. Gas stream 116 may enter gas
separation unit 120 to separate at least a portion of a gas
hydrocarbon stream 122, at least a portion of a hydrogen sulfide
stream 124, at least a portion of a carbon dioxide stream 126, at
least a portion of a sulfur dioxide stream 128, and at least a
portion of a hydrogen stream 130 from the gas stream 116.
[0054] One or more streams containing hydrogen sulfide from a
variety of sources, including the gas stream 116 from the
hydrocarbon formation, may be combined and sent to a gas separation
unit to produce the fuel stream comprising hydrogen sulfide
utilized in the process of the present invention. For example,
streams from gas reservoirs, liquid hydrocarbon reservoirs, and/or
streams from surface facilities may be combined as a feedstream for
the gas separation unit from which a hydrogen sulfide enriched gas
may be separated. The resulting hydrogen sulfide stream 124 may be
stored and/or combined with one or more hydrogen sulfide streams
produced from other gas separation units and/or other processing
facilities to form a fuel stream comprising hydrogen sulfide for
use in the process of the present invention.
[0055] Gas separation units 120 useful for forming the fuel stream
comprising hydrogen sulfide utilized in the process of the present
invention may include physical treatment systems and/or chemical
treatment systems. Physical treatment systems include, but are not
limited to, a membrane unit, a pressure swing adsorption unit, a
liquid absorption unit, and/or a cryogenic unit. Chemical treatment
systems may include units that use amines (for example,
diethanolamine or di-isopropanolamine), zinc oxide, sulfolane,
water, or mixtures thereof in the treatment process. In some
embodiments, gas separation unit 120 uses a Sulfinol gas treatment
process for removal of sulfur compounds. Carbon dioxide may be
removed using Catacarb.RTM. (Catacarb, Overland Park, Kans.,
U.S.A.) and/or Benfield (UOP, Des Plaines, Ill., U.S.A.) gas
treatment processes. The gas separation unit may be a rectified
adsorption and high pressure fractionation unit.
[0056] The fuel stream comprising hydrogen sulfide may be dried to
remove moisture to improve the combustibility of the fuel stream.
For example, the fuel stream comprising hydrogen sulfide may be
dried by contacting the hydrogen sulfide stream with ethylene
glycol to remove water.
[0057] In the process of the present invention, the oxidant in the
mixture comprising hydrogen sulfide and an oxidant is an
oxygen-containing gas or liquid. The oxidant is preferably selected
from compressed air, oxygen-enriched air, or oxygen gas. Compressed
air may be provided as the oxidant in the process of the invention
by compressing air by conventional air compressing processes, for
example, air may be compressed by passing the air through a turbine
compressor. Oxygen-enriched air, which may contain from 0.5 vol. %
to 15 vol. % more oxygen than air, may be produced by compressing
air and passing the compressed air through a membrane that reduces
the amount of nitrogen in the air. Oxygen gas may be provided as
the oxidant by conventional air separation technology.
[0058] In some embodiments, the ratio of hydrogen sulfide to
oxidant in the mixture combusted in the substantially vertical
wellbores is selected and controlled during the combustion process
and the combustion by-product gases are injected from the
substantially vertical wellbores into the hydrocarbon formation. By
selecting the amount of hydrogen sulfide relative to the amount of
oxidant present--on the basis of atomic sulfur to atomic oxygen
ratio or on a stoichiometric basis--and adjusting the amount of
hydrogen sulfide to the selected amount, the amount of hydrogen
sulfide in the combustion and the composition of the combustion
by-products produced (for example, sulfur dioxide and/or sulfur
trioxide) may be controlled. The amount of the fuel stream
comprising hydrogen sulfide may be controlled and/or the amount the
oxidant stream may be controlled to produce a mixture containing
selected ratio of hydrogen sulfide to oxidant for combustion such
that a preferred combustion by-product stream composition is
produced.
[0059] The amounts of a fuel stream comprising hydrogen sulfide and
an oxidant stream provided to produce a mixture for combustion in
the process of the present invention may be selected in a manner
such that combustion of the mixture generates substantially sulfur
trioxide in the combustion by-product stream. To produce a sulfur
trioxide-rich combustion by-product stream, the ratio of hydrogen
sulfide to oxidant may be selected so that excess oxidant is
present in the mixture for combustion relative to the hydrogen
sulfide content of the mixture. Combusting a hydrogen sulfide lean
mixture produces more sulfur trioxide than sulfur dioxide as a
combustion by-product. The sulfur trioxide may react with water in
the hydrocarbon formation to form sulfuric acid. Sulfur trioxide is
readily converted to sulfuric acid, thus heat of solution may be
produced and delivered to the hydrocarbon formation more rapidly
than when hydrogen sulfide is combusted at a stoichiometric amount
or deficient amount relative to the amount of oxidant.
[0060] Alternatively, the amounts of the fuel stream comprising
hydrogen sulfide and the oxidant in the mixture for combustion may
be selected in a manner such that combustion of the mixture
generates substantially sulfur dioxide in the combustion by-product
stream. To produce a sulfur dioxide-rich combustion by-product
stream, the ratio of hydrogen sulfide to oxidant in the mixture may
be selected so that a deficient amount of oxidant is present in the
mixture relative to the hydrogen sulfide content of the mixture.
Using an excess of hydrogen sulfide relative to oxidant in the
mixture for combustion produces a combustion by-products stream
rich in sulfur dioxide that also contains hydrogen sulfide, and
allows hydrogen sulfide and/or sulfur dioxide to be introduced into
the hydrocarbon containing formation. A portion of the hydrogen
sulfide and/or sulfur dioxide may contact at least a portion of the
formation fluids and solvate and/or dissolve a portion of the heavy
hydrocarbons in the formation fluids. Solvation and/or dissolution
of at least a portion the heavy hydrocarbons may facilitate
movement of the heavy hydrocarbons towards the production well.
Furthermore, introduction of at least a portion of the combustion
by-product stream comprising sulfur dioxide into the formation
fluids may increase a shear rate applied to hydrocarbon fluids in
the formation and decrease the viscosity of non-Newtonian
hydrocarbon fluids within the formation. The introduction of the
sulfur dioxide rich combustion by-products stream into the
formation may thereby increase a portion of the formation available
for production, and may increase a ratio of energy output of the
formation (energy content of products produced from the formation)
to energy input into the formation (energy costs for treating the
formation).
[0061] In a further alternative, the amounts of hydrogen sulfide
and the oxidant in the mixture provided for combustion may be
selected to provide stoichometrically equivalent amounts of
hydrogen sulfide and the oxidant. Combustion of a stoichiometric
amount of hydrogen sulfide with oxygen may generate predominately
sulfur dioxide and water as the combustion by-products as shown in
the following reaction:
H.sub.2S+1.5O.sub.2.fwdarw.SO.sub.2+H.sub.2O
(.DELTA.H.sub.r.times.n=-124 kcal/mol at 600.degree. K.).
[0062] In addition to the heat value that is obtained from
combustion of hydrogen sulfide, the introduction of heated sulfur
dioxide/water combustion by-product stream into the hydrocarbon
formation may facilitate recovery of hydrocarbons from the
formation. The heat from the sulfur dioxide may transfer heat to
fluids in the formation and the heated fluids may flow towards
production wells. Furthermore, as discussed above, the sulfur
dioxide in the combustion by-product stream may reduce the
viscosity of hydrocarbon formation fluids in the hydrocarbon
formation and thereby increase the amount of hydrocarbons available
to be recovered from the formation. The heat of solution of sulfur
dioxide, although less than the heat of solution of sulfuric acid,
may also be transferred to the formation fluids of the hydrocarbon
formation thereby mobilizing the formation fluids.
[0063] The combustion of the mixture comprising hydrogen sulfide
and the oxidant is effected in one or more heaters positioned in
one or more of the substantially vertical wellbores to generate
heat. The heaters include at least one flameless distributed
combustor, and may also include burners.
[0064] In a preferred embodiment, each heater is a flameless
distributed combustor in which the mixture comprising hydrogen
sulfide and the oxidant is flamelessly combusted. In a flameless
distributed combustor, the oxidant is provided to the combustor as
an oxidant stream at a velocity that is sufficiently elevated to
prevent the formation of a fixed diffusion flame upon combustion of
the mixture of the oxidant and the hydrogen sulfide in the heater,
thereby ensuring a controlled heat release along the length of the
flameless distributed combustor.
[0065] In operating a flameless distributed combustor heater to
combust the mixture comprising hydrogen sulfide and the oxidant
stream, the hydrogen sulfide, preferably provided in a gas stream,
and the oxidant are mixed, where the mixture of the hydrogen
sulfide and the oxidant is heated to a temperature at or above the
auto-ignition temperature of the mixture, typically from
250.degree. C. to 800.degree. C., or from 300.degree. C. to
750.degree. C., or from 400.degree. C. to 700.degree. C. (where the
auto-ignition temperature of a fuel stream of pure hydrogen sulfide
is 260.degree. C.)
[0066] Prior to mixing the oxidant stream and the fuel stream
comprising hydrogen sulfide in the heater, the oxidant stream, the
fuel stream, or both may be pre-heated to a temperature sufficient
to bring the mixture to a temperature at or above the auto-ignition
temperature of the mixture upon mixing. The oxidant stream and/or
the fuel stream comprising hydrogen sulfide may be pre-heated by
heat exchange with a heat source, for example, steam or superheated
steam. Alternatively, the fuel stream comprising hydrogen sulfide
and the oxidant stream may be mixed and ignited using an ignition
device--such as a spark plug or a glow plug--that facilitates
raising the temperature of the mixture to at or above the
auto-ignition temperature of the mixture.
[0067] The heaters may also include one or more burners that
produce a flame. In operating a burner, the fuel stream comprising
hydrogen sulfide and the oxidant stream are provided to the burner
for combustion. The fuel stream and the oxidant stream may be mixed
in the burner or may be mixed prior to being provided to the
burner. The mixture of the fuel stream comprising hydrogen sulfide
and the oxidant stream is combusted by raising the temperature of
the mixture to a temperature at or above the auto-ignition
temperature of the mixture, for example, by igniting the mixture
with an ignition device such as a spark plug or a glow plug. The
oxidant stream and the fuel stream comprising hydrogen sulfide are
provided to the burner at a velocity such that a stable flame may
be produced by the burner. The burner may include flame stabilizing
shields near the burner flame to assist in stabilizing the flame
after ignition.
[0068] Combustion of the mixture of hydrogen sulfide and the
oxidant generates heat. Heat from the combustion is transferred to
a portion of the hydrocarbon containing formation located between
at least one of the substantially horizontal steam injection wells
and at least one of the substantially vertical heater wells. Heat
from the combustion of the mixture of hydrogen sulfide and the
oxidant may be directed from a substantially vertical heater well
to a portion of the hydrocarbon containing formation located
between the heater well and a substantially horizontal steam
injection well by injecting a combustion by-product stream produced
from the combustion from the heater well into the hydrocarbon
formation, where the combustion by-product stream carries at least
a portion of the heat of combustion from the heater well to the
hydrocarbon containing formation. In an embodiment of the process
of the present invention, the combustion by-product stream may be
injected into the hydrocarbon containing formation from the end of
the substantially vertical heater well located nearest the
substantially horizontal steam injection well.
[0069] Heat may be transferred to fluids introduced into the
formation, formation fluids and/or to a portion of the hydrocarbon
containing formation through heat of reaction, heat of salvation,
conductive heat, or convective heat. Fluids introduced into the
formation and/or combustion by-products may transfer heat to at
least a portion of the hydrocarbon containing formation and/or
formation fluids.
[0070] Convective heat transfer may occur when non-condensable
non-miscible gases such as nitrogen contact the formation fluids
and/or hydrocarbon containing formation. When the oxidant stream is
formed of compressed air or oxygen-enriched air, the combustion
by-products may include nitrogen gas. Convective heat transfer may
also occur when superheated miscible solvent vapors (for example,
hydrogen sulfide, carbon dioxide, and/or sulfur dioxide vapors)
contact the formation fluids and/or hydrocarbon containing
formation. Convective heat transfer may also occur when superheated
non-miscible solvent vapors such as water contact the formation
fluids and/or hydrocarbon containing formation.
[0071] Conductive heat transfer may occur when hot liquid steam
condensate contacts the formation fluids and/or hydrocarbon
containing formation. Conductive heat transfer may occur when hot
liquid miscible solvent (for example, hydrogen sulfide, carbon
dioxide, and/or sulfur dioxide) contacts the formation fluids
and/or hydrocarbon containing formation.
[0072] Heat of reaction heat transfer may occur when one compound
reacts with another compound. For example, sulfur oxides form
solutions with liquid water in the hydrocarbon containing formation
and/or in the outer portion of the wellbore to generate a heat of
reaction. Heat of reaction also occurs as oxygen reacts with
hydrocarbons or sulfur compounds to form carbon oxides or sulfur
oxides.
[0073] Heat of solution may occur when at least one component is
dissolved in a solvent. For example, heat is generated when
sulfuric acid is dissolved in water.
[0074] The heat transferred from the one or more substantially
vertical heater wells to the hydrocarbon containing formation heats
at least a portion of the portion of the hydrocarbon containing
formation located between the substantially horizontal steam
injection well and the substantially vertical heater well located
within ten meters of the end of the substantially horizontal steam
injection well. At least a portion of the formation fluids in the
heated portion of the hydrocarbon containing formation are
mobilized by the transfer of heat from the heater well(s) to the
hydrocarbon formation. The mobilized formation fluids may be
collected by a production well and a hydrocarbon material including
formation fluids mobilized by the heat transfer or driven by the
mobilized formation fluids may be produced from the hydrocarbon
containing formation.
[0075] FIGS. 3 through 7 are embodiments of hydrogen sulfide fueled
heaters 130 for subsurface heating. FIGS. 3 through 6 depict
cross-sections of hydrogen sulfide fueled flameless distributed
combustors. FIG. 7 depicts a cross-section of a hydrogen sulfide
fueled burner.
[0076] FIG. 3 depicts a perspective of a portion of hydrogen
sulfide fueled flameless distributed combustor 150 positioned in
vertical wellbore 102. Fuel stream 152 comprising hydrogen sulfide
(for example, gas stream 116 and/or hydrogen sulfide stream 124
optionally including sulfur dioxide stream 128, hydrogen stream
130, and/or gas hydrocarbon stream 122 from FIG. 2) enters central
fuel conduit 154. Oxidant stream 156 (for example, air, oxygen
enriched air, oxygen gas, or mixtures thereof) enters combustion
conduit 158. In some embodiments, heat from water 162 heats fuel
stream 152, oxidant stream 156, and/or the fuel/oxidant mixture to
a temperature at or above the auto-ignition temperature necessary
to cause combustion of the fuel stream mixture. In some
embodiments, fuel stream 152 and/or oxidant stream 156 are heated
prior to entering the fuel conduit and/or combustion conduit to a
temperature at or above the auto-ignition temperature of the
mixture. Oxidant stream 156 and fuel stream 152 mix, and the
fuel/oxidant mixture reacts (combusts) at a temperature at or above
the auto-ignition temperature of the mixture.
[0077] Central fuel conduit 154 is positioned inside of combustion
conduit 158 and may extend the length of flameless distributed
combustor 150. Central fuel conduit 154 includes orifices 160 along
the length of the central fuel conduit. Orifices 160 may be
critical flow orifices. Orifices 160 allow heated fuel to mix with
heated oxidant so that the mixture reacts (flamelessly combusts) to
produces heat. In some embodiments, orifices 160 are shaped to
allow a fuel to oxidant momentum ratio to range from 10 to 100,
from 30 to 80, or from 50 to 70, where momentum is equal to the
density of the fuel or oxidant times velocity of the fuel or
oxidant squared. In some embodiments, a fuel to oxidant pressure
ratio through orifices 160 ranges from 1.5 to 2.
[0078] Combustion in a downstream portion of combustion conduit 158
may transfer heat to water 162 in outer conduit 164. In some
embodiments, the water is heated to form steam and/or super heated
steam. Outer conduit 164 may be the space formed between the inner
wall of injection well 102 and outer wall of combustion conduit
158. Outer conduit 164 may include openings 104 that allow the
water and/or heat to enter the hydrocarbon layer adjacent to the
injection well. In some embodiments, outer conduit 164 is a conduit
that surrounds combustion conduit 158 and is coupled to or an
integral part of flameless distributed combustor 150. Coupling
outer conduit 164 to flameless distributed combustor 150 may
facilitate insertion of the flameless distributed combustor into an
existing injection well.
[0079] In some embodiments, combustion of fuel in combustion
conduit 158 produces a combustion by-products stream. Combustion
by-products stream may heat water 162. The combustion by-products
stream may exit openings 104 and drive, heat, and/or reduce
viscosity of formation fluids in the hydrocarbon containing
formation. Contact of water with the combustion by-products stream
in a portion of the formation at a distance from well 102 may
generate heat, and heat at least a portion of the formation to
allow fluids to be mobilized.
[0080] In some embodiments, a portion or portions of central fuel
conduit 154 are adjustable. The ability to adjust central fuel
conduit 154 allows fuel to be provided to selected portions of
combustion conduit 158. For example, positioning central fuel
conduit 154 at an upstream portion of the flameless distributed
combustor may facilitate the combustion process in the upstream
portion of the well at a desired time. Once combustion is
established, the fuel conduit may be advanced along the length of
the injection well (or selected valves may be opened along the
length of the injection well) to provide fuel to other combustors
positioned in the well. In some embodiments, orifices 160 may be
adjusted to allow flow of fuel into combustion conduit 158. For
example orifices, 160 may be connected to a computer system that
opens and/or closes the orifices as required.
[0081] FIG. 4 depicts central fuel conduit 154 having inner fuel
conduit 166 and outer fuel conduit 168. Inner fuel conduit 166 may
be coupled and/or removably coupled to outer fuel conduit 168.
Inner fuel conduit 166 may fit inside of outer fuel conduit 168
such that a space is formed between the two conduits. In some
embodiments, the two conduits are co-axial. In some embodiments,
the conduits are separate and parallel.
[0082] Hydrogen sulfide stream 124 enters inner fuel conduit 166
and flows into outer fuel conduit 168 through orifices 170. In some
embodiments, hydrogen sulfide is delivered to outer fuel conduit
168 through an opening in a downstream portion (for example, the
end of fuel conduit is open) of inner fuel conduit 166. Fuel stream
152 enters outer fuel conduit 168. In some embodiments, a portion
of inner fuel conduit 166 relative to outer fuel conduit 168 is
adjustable to allow for removal of either of the conduits for
maintenance purposes, and/or for selected delivery of hydrogen
sulfide and/or fuel to selected portions of the flameless
distributed combustor. Delivery of hydrogen sulfide as a separate
stream may allow for control of the amount of hydrogen sulfide in
the fuel stream provided to combustion conduit 158. In some
embodiments, outer conduit 168 is the hydrogen sulfide conduit and
fuel is delivered to the formation through inner conduit 166.
[0083] FIG. 5 depicts flameless distributed combustor 150 having
more than one fuel conduit. As shown, the fuel conduits are
separate and parallel to one another. In some embodiments, the
conduits are co-axial. Fuel conduits 154, 154', 154'' include
orifices 160, 160', 160'' positioned at different intervals along
the fuel conduits. Positioning of the orifices 160, 160', 160'' may
allow for delivery of fuel to selected portions of flameless
distributed combustor 150 at selected time periods. For example,
fuel stream 152 may be delivered to an upstream portion of
combustion conduit 158 through orifice 160. Combustion of fuel 152
in the upstream portion of the combustion conduit 158 may provide
heat to steam 162 in upstream portion of outer conduit 164. Fuel
stream 152' enters a middle portion of combustion conduit 158
through orifices 160', mixes with oxidant, and then react to
provide heat to steam in a middle portion of outer conduit 164.
Fuel stream 152'' delivered through orifices 160'' in fuel conduit
154'' and subsequent combustion in downstream portion of combustion
conduit 158 provides heat to steam in a downstream portion of outer
conduit 164. In some embodiments, fuel streams 152, 152', 152''
contain different amounts of hydrogen sulfide. In some embodiments,
fuel streams 152, 152', 152'' contain the same amounts of hydrogen
sulfide. It should be understood that the number of fuel conduits
and/or position of the orifices in the fuel conduit may be varied.
In some embodiments, orifices 160, 160', 160'' are adjusted (opened
and/or closed) to control the flow of fuel and/or hydrogen sulfide
into combustion conduit 158.
[0084] FIG. 6 depicts a cross-section of flameless distributed
combustor 150 with ignition device 172. Ignition device 172 may
raise the temperature of the fuel/oxidant mixture to combustion
temperatures in combustion conduit 158. For example, once the
fuel/oxidant mixture is ignited near ignition device 172, heat from
the flame heats the fuel/oxidant mixture to an auto-ignition
temperature of the fuel/oxidant mixture to facilitate the reaction
of the fuel with the oxidant to produce flameless combustion and
heat.
[0085] FIG. 7 depicts a perspective of hydrogen sulfide fueled
burner 174. Burner 174 may include fuel conduit 176, combustion
conduit 158, and outer conduit 164. Ignition device 172 may be
positioned in a bottom portion of combustion conduit 158. Fuel
stream 152 (for example, gas stream 116, hydrogen sulfide stream
124, sulfur dioxide stream 128, hydrogen stream 130, and/or gas
hydrocarbon stream 122 from FIG. 2, (methane, natural gas, sour
gas, or mixtures thereof) enters central fuel conduit 176. Oxidant
stream 156 (for example, air, oxygen enriched air, or mixtures
thereof) enters combustion conduit 158. In some embodiments, burner
174 may include more than one fuel conduit. For example, one
conduit for hydrogen sulfide and one conduit or a fossil fuel. In
some embodiments, fuel conduit 176 is combustion conduit 158 and
combustion conduit is fuel conduit 176.
[0086] In some embodiments, fuel stream 152 and/or oxidant stream
156 are heated prior to entering the fuel conduit and/or combustion
conduit. In some embodiments, water 162 heats fuel stream 152
and/or oxidant stream 156. Fuel stream 152 and oxidant stream 156
mix in combustion conduit 158. Ignition device 172 provides a spark
to combust the fuel/oxidant mixture to produce a flame.
[0087] In some embodiments, burner includes one or more nozzles
178. The fuel and oxidant may be mixed by flowing at least a
portion of the fuel and at least a portion of the oxidant through
nozzles 178. Nozzles 178 may enhance mixing in combustion conduit
158 and/or outer conduit 164. Geometry of nozzles 178 (for example,
converging-diverging section dimensions, length, diameter, and/or
flare angle) may be adjusted based on firing rate, fuel stream
composition, and/or oxidant stream composition. A nozzle flare
angle may range from 1 degree to 10 degrees, from 2 degrees to 9
degrees, or from 3 degrees to 8 degrees in the flow direction. In
some embodiments, nozzles 178 are shaped to allow concentric flow
or counter-concentric flow (swirling of the mixture). The nozzle
swirl angle may range from 10 degrees to 40 degrees, from 15
degrees to 35 degrees, or from 20 degrees to 30 degrees. In some
embodiments, the nozzle swirl angle is 30 degrees. In some
embodiments, burner 174 does not include nozzles 178.
[0088] In some embodiments, a downstream portion of fuel conduit
176 may be tapered. The taper angle may range from 5 to 30 degrees,
from 10 degrees to 25 degrees, or from 15 degrees to 20
degrees.
[0089] Combustion of the fuel/oxidant mixture in combustion conduit
158 of burner 174 may transfer heat to water 162 in outer conduit
164. In some embodiments, the water is heated to form steam and/or
super heated steam. Outer conduit 164 may be the space formed
between the inner wall of injection well 102 and outer wall of
combustion conduit 158. Outer conduit 164 may include openings 104
that allow the water and/or heat to enter the hydrocarbon layer
adjacent to the injection well. In some embodiments, outer conduit
164 is a conduit that surrounds combustion conduit 158 and is
coupled to or an integral part of burner 174. Coupling outer
conduit 164 to burner 174 may facilitate insertion of the burner
into an existing injection well. In some embodiments, the outer
conduit is the fuel conduit and water is delivered through the
inner conduit.
[0090] In some embodiments, combustion of the fuel/oxidant mixture
in combustion conduit 158 of burner 174 produces the combustion
by-products stream. Combustion by-products stream may heat water
162. The combustion by-products stream may exit openings 104 and
drive, heat, and/or reduce viscosity of formation fluids in the
hydrocarbon containing formation. Contact of water with the
combustion by-products stream in a portion of the formation at a
distance from well 102 may generate heat and heat at least a
portion of the formation to allow fluids to be mobilized.
[0091] Heaters 130 (for example, flameless distributed combustors
and burners described in FIGS. 3-7) may be manufactured from
materials suitable for downhole combustion processes. In some
embodiments, water present in the fuel and/or hydrogen sulfide
streams interacts with hydrogen sulfide to form a sulfide layer on
metal surfaces of the conduit walls. Formation of the sulfide layer
may inhibit further corrosion of the metal surfaces of the conduit
walls by carbonic acid and/or other acids. The formation of the
sulfide layer may allow outer conduit 164, central fuel conduit
154, and combustion conduit 158 to be fabricated from carbon steel
or other alloys. For example, alloy 230, alloy 800H, alloy 370H or
Hastelloy C276 may be used to manufacture portions of heaters 130.
In some embodiments, inner fuel conduit 166 (shown in FIG. 4) is
manufactured from materials resistant to high temperature and/or
high concentrations of hydrogen sulfide.
[0092] In some embodiments, a start-up mixture of hydrocarbon fuel
containing a minimal amount of hydrogen sulfide or a less than a
stoichiometric amount of hydrogen sulfide relative to the amount of
oxidant is introduced into fuel conduit 154 of heaters 130 (for
example, flameless distributed combustor 150 and/or burner 174). In
some embodiments, a start up fuel stream includes at most 1%, at
most 0.5%, at most 0.01% by volume of hydrogen sulfide. In some
embodiments, the start-up fuel includes hydrogen and/or oxygenated
ethers such as dimethyl ether to lower the ignition temperature.
Once combustion has been initiated, the hydrogen sulfide
concentration in fuel stream 152 may be increased.
[0093] In some embodiments, a mixture containing a low amount of
hydrogen sulfide relative to oxidant is not necessary for start-up
and/or for sustaining combustion. For example, the fuel stream may
include from 0.1% to 100%, from 3% to 90%, from 10% to 80%, or from
20% to 50% of hydrogen sulfide by volume. In some embodiments, the
fuel has a sulfur content of at least 0.01 grams, at least 0.1
grams, at least 0.5 grams or at least 0.9 grams of atomic sulfur
per gram of fuel as determined by ASTM Method D4294.
[0094] FIG. 8 depicts a representation of a system for producing
hydrocarbons using a substantially vertical hydrogen sulfide fueled
heater in combination with a substantially horizontal or inclined
steam injection well. Vertical heater well 186 may be positioned
proximate the downstream portion of horizontal steam injection well
102. For example, vertical heater well 186 may be positioned from 1
to 10 meters from the end of horizontal injection well 102.
Production well 108 extends past injection well 102 and below
heater well 186. Vertical heater well 186 includes hydrogen sulfide
fueled heaters 130 described herein. Heat generated from heater
well 186 through oxidation of hydrogen sulfide in heaters 130 may
mobilize hydrocarbons towards production well 108. Heat transfer
produced from hydrogen sulfide fueled heater well 186, in
combination with heat and stream drive from steam injection well
102, may allow more hydrocarbons to be produced from production
well 108 as compared to conventional drive processes using
horizontal injection wells.
[0095] Further modifications and alternative embodiments of various
aspects of the invention will be apparent to those skilled in the
art in view of this description. Accordingly, this description is
to be construed as illustrative only and is for the purpose of
teaching those skilled in the art the general manner of carrying
out the invention. It is to be understood that the forms of the
invention shown and described herein are to be taken as examples of
embodiments. Elements and materials may be substituted for those
illustrated and described herein, parts and processes may be
reversed and certain features of the invention may be utilized
independently, all as would be apparent to one skilled in the art
after having the benefit of this description of the invention.
Changes may be made in the elements described herein without
departing from the spirit and scope of the invention as described
in the following claims.
* * * * *