U.S. patent application number 12/424859 was filed with the patent office on 2009-10-22 for method for treating a hydrocarbon containing formation.
Invention is credited to Jingyu Cui, Mahendra Ladharam Joshi, Stanley Nemec Milam, Michael Anthony REYNOLDS, Scott Lee Wellington.
Application Number | 20090260810 12/424859 |
Document ID | / |
Family ID | 41199755 |
Filed Date | 2009-10-22 |
United States Patent
Application |
20090260810 |
Kind Code |
A1 |
REYNOLDS; Michael Anthony ;
et al. |
October 22, 2009 |
METHOD FOR TREATING A HYDROCARBON CONTAINING FORMATION
Abstract
Methods of generating subsurface heat for treatment of a
hydrocarbon containing formation are described herein. Methods
include providing steam to at least a portion of a hydrocarbon
containing formation from a plurality of locations in a wellbore.
The steam is hotter than a temperature of the portion. The steam is
heated in the wellbore by combusting a stream comprising hydrogen
sulfide in the wellbore. Heat from the combustion transfers to the
steam. The steam provided the portion at a first location in the
wellbore is hotter than steam provided at a second location in the
wellbore along the length of the wellbore, where the first location
is further from a surface of the formation than the second location
along the length of the wellbore.
Inventors: |
REYNOLDS; Michael Anthony;
(Katy, TX) ; Cui; Jingyu; (Katy, TX) ;
Wellington; Scott Lee; (Bellaire, TX) ; Joshi;
Mahendra Ladharam; (Katy, TX) ; Milam; Stanley
Nemec; (Houston, TX) |
Correspondence
Address: |
SHELL OIL COMPANY
P O BOX 2463
HOUSTON
TX
772522463
US
|
Family ID: |
41199755 |
Appl. No.: |
12/424859 |
Filed: |
April 16, 2009 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61046166 |
Apr 18, 2008 |
|
|
|
Current U.S.
Class: |
166/272.3 ;
166/272.6 |
Current CPC
Class: |
E21B 43/2408 20130101;
E21B 36/02 20130101; E21B 43/2406 20130101; E21B 43/162
20130101 |
Class at
Publication: |
166/272.3 ;
166/272.6 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 36/00 20060101 E21B036/00; E21B 36/02 20060101
E21B036/02; 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 locations in a wellbore,
wherein the steam has a higher temperature than the portion of the
hydrocarbon containing formation; and heating the steam in the
wellbore by combusting at least a portion of a mixture comprising
fuel and oxidant in the wellbore and transferring heat from the
combustion to the steam, wherein the fuel comprises hydrogen
sulfide, and wherein the steam is heated such that the steam
provided to the portion of the hydrocarbon containing formation at
a first location in the wellbore is hotter than steam provided at a
second location in the wellbore, and wherein the first location is
further from a surface of the formation than the second location
along the length of the wellbore.
2. The method of claim 1, wherein a portion of the steam is
provided in an outer portion of at least one of the wellbores, and
combustion occurs in one or more heaters in an inner portion of the
wellbore, and the inner portion of the wellbore communicates with
the outer portion of the wellbore such that at least a portion of
the generated heat provides heat to a portion of the steam.
3. The method of claim 1, wherein a portion of the steam is
provided in an outer portion of at least one of the wellbores, and
combustion occurs in one or more heaters in an inner portion of the
wellbore, and the inner portion of the wellbore communicates with
the outer portion of the wellbore such that at least a portion of
the generated heat provides heat to a portion of the steam to a
temperature at or above the auto-ignition temperature of the
fuel/oxidant mixture.
4. The method of claim 1, wherein combustion generates a combustion
by-products stream and the method further comprises contacting at
least a portion of the combustion by-products stream with a portion
of the water in a portion of the hydrocarbon containing formation
that is downstream of the formation surface, along the length of
the wellbore, from the transferred heat portion.
5. The method of claim 4, further comprising driving formation
fluids with at least a portion of the combustion by-products stream
and a portion of the steam.
6. The method of claim 1, further comprising mobilizing formation
fluids in the hydrocarbon formation by providing the steam to the
portion of the hydrocarbon formation.
7. The method of claim 1, wherein at least a portion of the
hydrogen sulfide is produced from formation fluids obtained from
the hydrocarbon containing formation.
8. The method of claim 1, further comprises controlling where the
second location is along the length of the wellbore.
9. The method of claim 1, further comprising controlling heat flux
along the length of the wellbore.
10. The method of claim 1, wherein heat at the second location is
proximate to a portion of formation richer in hydrocarbons, as
compared to the first location.
11. The method of claim 1, wherein the stream comprising steam
further comprises carbon dioxide, nitrogen, and/or sulfur
dioxide.
12. 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 locations in a wellbore,
wherein the wellbore extends from the surface into the portion of
the hydrocarbon formation, and wherein the steam has a higher
temperature than the portion of the hydrocarbon containing
formation; heating the steam in the wellbore by combusting a stream
comprising hydrogen sulfide in the wellbore, wherein heat from the
combustion transfers to the steam, wherein the steam is heated such
that steam provided to the portion at a first location in the
wellbore is hotter than steam provided at a second location in the
wellbore, and wherein the first location is further along the
length of the wellbore, as measured from the surface, than the
second location; transferring at least a portion of the heat at the
first location to at least a portion the hydrocarbon containing
formation; transferring at least a portion of the heat at the
second location to at least a portion of the hydrocarbon formation;
and mobilizing at least a portion of formation fluids in the heated
portion of the hydrocarbon formation.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from U.S. Provisional
Application Ser. No. 61/046,166 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] In situ heating of a selected section of a hydrocarbon
formation has been used for directed heating of portions of a
hydrocarbon formation. U.S. Pat. No. 7,066,257 to Wellington et al
describes an in situ treatment of a formation that includes heating
a selected section of a hydrocarbon formation with one or more heat
sources and one or more cycles of steam injection. A vapor mixture,
which may include pyrolysis fluids, may be produced from the
formation through one or more production wells in the formation.
The heat sources may include natural distributed combustors that
are fueled by methane, ethane, hydrogen, or synthesis gas. Fluid
produced from the formation may include hydrogen sulfide. The
hydrogen sulfide produced from the formation may be used to
produce, for example, sulfuric acid, fertilizer, and/or elemental
sulfur.
[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 formation from a plurality of locations in
a wellbore, wherein the steam has a higher temperature than the
portion of the hydrocarbon containing formation; and heating the
steam in the wellbore by combusting at least a portion of a mixture
comprising fuel and oxidant in the wellbore and transferring heat
from the combustion to the steam, wherein the fuel comprises
hydrogen sulfide, and wherein the steam is heated such that the
steam provided to the portion of the hydrocarbon containing
formation at a first location in the wellbore is hotter than steam
provided at a second location in the wellbore, and wherein the
first location is further from a surface of the formation than the
second location along the length of the wellbore.
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 from a hydrocarbon containing formation
using a hydrogen sulfide fueled heater.
[0019] FIG. 9 depicts a representation of a heat flux profile of a
conventional steam injection process.
[0020] FIGS. 10A and 10B depict representations of a heat flux
profile of an embodiment of heating of steam using a hydrogen
sulfide fueled heater.
[0021] FIG. 11 depicts a representation of an embodiment for
producing hydrocarbons using a vertical hydrogen sulfide fueled
heater in combination with a horizontal steam injection well.
[0022] 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 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
[0023] The present invention is directed to providing subsurface
heat to a hydrocarbon formation where the heat is generated by 1)
providing steam to a portion of a hydrocarbon formation from a
plurality of locations (at least two) in a wellbore; and 2) heating
the steam in the wellbore by combusting a mixture of fuel
comprising hydrogen sulfide and an oxidant. The steam is hotter
than the portion of the hydrocarbon formation at each location at
which the steam is provided to the portions of the hydrocarbon
formation so that heat is transferred from the steam to the
hydrocarbon formation to mobilize formation fluids so they can be
recovered. Heat produced by combusting the mixture of the fuel
comprising hydrogen sulfide and an oxidant is transferred to the
steam to heat the steam, where the steam is heated so that steam
provided to the hydrocarbon formation at a first location is hotter
than steam provided to the hydrocarbon formation at a second
location, where the first location is further from the surface of
the formation along the wellbore than the second location. This
enables an energy efficient consistent heat profile to be provided
to the hydrocarbon formation along the entire length of the
wellbore; compensating for loss of heat as steam injected into the
wellbore at the surface of the formation cools as it traverses the
length of the wellbore. Furthermore, 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.
[0024] 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).
[0025] 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.
[0026] Terms used herein are defined as follows.
[0027] "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.
[0028] "ASTM" refers to American Standard Testing and
Materials.
[0029] 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.
[0030] "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.
[0031] 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.
[0032] "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.
[0033] "Hydrocarbons" are generally defined as molecules formed
primarily by carbon and hydrogen atoms. 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.
[0034] "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.
[0035] "SAGD" is steam assisted gravity drainage.
[0036] "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..
[0037] "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.
[0038] "Water" refers to the liquid and vapor phases of water. For
example, water, steam, super-heated steam.
[0039] In the process of the invention, steam is provided through
one or more wellbores to a hydrocarbon formation. The steam is
provided to at least a portion of the hydrocarbon containing
formation from a plurality of locations in a wellbore, where the
plurality of locations comprises at least two locations. In an
embodiment of the process of the present invention, the steam may
be provided in a wellbore to a first portion of the hydrocarbon
formation at a first location and may be provided in the wellbore
to a second portion of the hydrocarbon formation at a second
location. The steam provided to the hydrocarbon formation has a
higher temperature than the portion of the hydrocarbon formation to
which the steam is provided.
[0040] In the process of the present invention, the steam is heated
in the wellbore by combusting at least a portion of a mixture of a
fuel comprising hydrogen sulfide and an oxidant in the wellbore and
transferring heat from the combustion to the steam. The steam is
heated such that the steam provided to the portion of the
hydrocarbon containing formation at the first location in the
wellbore is hotter than the steam provided to the portion of the
hydrocarbon formation at a second location in the wellbore, where
the first location is further from the intersection of the surface
of the formation and the wellbore than the second location along
the length of the wellbore. Heating the hydrocarbon formation at a
location further along the wellbore from the surface of the
hydrocarbon formation with steam that is as hot or hotter than
steam used to heat the hydrocarbon formation at a location nearer
the surface of the hydrocarbon formation along the length of the
wellbore permits either 1) substantially uniform heating to be
provided from the steam to the hydrocarbon formation along the
entire length of the wellbore; or 2) more heat to be provided by
the steam to the hydrocarbon formation at a location further from
the surface of the hydrocarbon formation along the length of the
wellbore than at a location nearer the surface of the hydrocarbon
formation along the length of the wellbore-allowing more heat to be
provided selectively to a portion of the hydrocarbon formation
further from the surface of the formation along the wellbore.
[0041] In the present invention, the mixture of the fuel stream
comprising hydrogen sulfide and the oxidant is combusted in one or
more heaters positioned in the wellbore in which the steam is
provided to the hydrocarbon formation. The heat from the combustion
is transferred to the steam at a plurality of locations--at least
two--in the wellbore so the heated steam may transfer heat to
portions of the hydrocarbon formation. The combustion of the fuel
stream produces a combustion by-products stream that comprises one
or more sulfur oxides. The combustion by-product stream may be
contacted with water in the hydrocarbon formation to release a heat
of solution into the hydrocarbon formation, further heating the
hydrocarbon formation. The water with which the combustion
by-products stream is contacted may be water in the hydrocarbon
formation, water produced by the combustion of the fuel stream with
an oxidant, or water provided through one or more wellbores to at
least a portion of the hydrocarbon formation by providing steam to
the hydrocarbon formation.
[0042] In an embodiment of the process of the invention, the
process may be utilized in conjunction with a drive process to
treat a hydrocarbon formation. Such drive processes include, but
are not limited to, steam injection processes such as cyclic steam
injection, SAGD, solvent injection, a vapor solvent and SAGD
process, or carbon dioxide injection. The process of the invention
may be used to preheat a hydrocarbon formation for a drive process,
or may be used to provide heat during or after a drive process.
[0043] 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. Steam 100 may be injected at
temperatures ranging from 100.degree. C. to 500.degree. C.,
preferably 150.degree. C. to 300.degree. C., and pressures ranging
from 1 MPa to 15 MPa. 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.
[0044] Heaters may be positioned in the injection well 102 in which
a fuel stream comprising hydrogen sulfide may be combusted with an
oxidant according to the process of the invention to provide
further heat to the hydrocarbon formation to further mobilize the
formation fluids 110. Combustion by-products containing sulfur
oxides may mix with the steam from the injection well in the
hydrocarbon formation to provide even further heat to the
hydrocarbon formation by releasing the heat of solution formed upon
contact of the sulfur oxides with the steam into the hydrocarbon
formation.
[0045] In the process of the present invention, a fuel stream
comprising hydrogen sulfide that is provided to a heater 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.
[0046] 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.
[0047] 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.
[0048] The fuel stream comprising hydrogen sulfide used in the
process of the present invention may include from 1% to 100%, from
3% to 90%, from 10% to 80%, or from 20% to 70%, or from 30% to 60%,
or from 40% to 50% of hydrogen sulfide by volume, or may include at
least 10%, or at 20% 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. In
an embodiment of the process of the invention, produced formation
fluids from a hydrocarbon formation including hydrogen sulfide
stream 124 in combination with gas stream 116, hydrogen stream 130,
and/or gas hydrocarbon stream 122 may be used as a fuel stream
comprising hydrogen sulfide.
[0049] 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.
[0050] In the process of the present invention, the oxidant with
which the fuel stream comprising hydrogen sulfide is combusted 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.
[0051] In some embodiments, the ratio of hydrogen sulfide to
oxidant is controlled during the combustion process. By selecting
the amount of hydrogen sulfide relative to the amount of oxidant
present in the mixture to be combusted-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 selected ratio of hydrogen sulfide to oxidant for
combustion such that a preferred combustion by-product stream
composition is produced.
[0052] The amounts of the fuel stream comprising hydrogen sulfide
and the oxidant stream mixed for combustion in the process of the
present invention may be controlled 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 in the combustion mixture may be controlled so
that excess oxidant is combusted with the fuel stream comprising
hydrogen sulfide relative to the hydrogen sulfide content of the
fuel stream. 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.
[0053] Alternatively, the amounts of the fuel stream comprising
hydrogen sulfide and the oxidant provided in the mixture for
combustion in the process of the present invention may be
controlled in a manner such that combustion 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 may be controlled so that a deficient
amount of oxidant is present in the combustion mixture relative to
the hydrogen sulfide content of the fuel stream. Using an excess of
hydrogen sulfide relative to oxidant 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 a layer of 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).
[0054] In a further alternative, the amounts of the fuel stream
comprising hydrogen sulfide and the oxidant provided in the mixture
for combustion in the process of the present invention may be
controlled 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).
[0055] 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.
[0056] The combustion of the mixture of the fuel stream comprising
hydrogen sulfide and the oxidant stream may be effected in one or
more heaters positioned in each of the one or more wellbores
through which steam is provided to the hydrocarbon formation. The
heaters may be flameless distributed combustors, burners, or a
mixture of both.
[0057] In a preferred embodiment, each heater is a flameless
distributed combustor in which the mixture of the fuel stream
comprising hydrogen sulfide and the oxidant stream are flamelessly
combusted. In a flameless distributed combustor, the oxidant stream
is provided in the heater 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 fuel stream in the
heater, thereby ensuring a controlled heat release along the length
of the flameless distributed combustor.
[0058] In operating a flameless distributed combustor heater to
combust the fuel stream comprising hydrogen sulfide and the oxidant
stream, the fuel stream and the oxidant are mixed, where the
mixture of the fuel stream 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.). 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.
[0059] The heater may also be a burner that produces 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 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.
[0060] As noted above, in the process of the present invention
steam is provided to at least a portion of the hydrocarbon
containing formation through one or more of the wellbores in which
the fuel stream comprising hydrogen sulfide and the oxidant stream
are combusted. The steam provided to the one or more wellbores may
be in the form of steam or superheated steam.
[0061] At least a portion of the steam supplied to a wellbore may
be heated subsurface by the heat generated by the combustion of the
fuel stream comprising hydrogen sulfide and the oxidant stream. The
heat generated by combustion of the fuel stream comprising hydrogen
sulfide and the oxidant stream may be thermally communicated to one
or more portions of the steam in the wellbore at one or more
locations in the wellbore. The one or more heated portion(s) of the
steam may be in thermal communication with one or more portions of
the hydrocarbon formation at one or more locations in the wellbore
so that heat may be transferred from the heated portion(s) of the
steam to the hydrocarbon formation at the one or more locations to
provide a driving force for mobilization of at least a portion of
the formation fluids in the hydrocarbon formation. The heated
portion(s) of the steam may be in thermal communication with the
hydrocarbon formation along the length of the wellbore, and the
heated portion(s) of the steam may be injected into the hydrocarbon
formation at the one or more locations along the length of the
wellbore and/or at the terminus of the wellbore.
[0062] Combustion of the fuel stream comprising hydrogen sulfide
and the oxidant stream may be effected subsurface in the wellbore
of the injection well to provide heat for subsurface heating of the
steam. The steam may be heated subsurface by combustion a mixture
of the fuel stream comprising hydrogen sulfide and the oxidant
stream in a subsurface section of the wellbore of the injection
well and transfer of the heat from the combustion to the steam in
the wellbore. Heat from the subsurface combustion may enhance heat
transfer to the hydrocarbon formation due to the generation of
higher steam temperatures subsurface, thus the heat transfer region
or "region of influence" (ROI) may be enlarged as compared to
conventional steam drive processes. For example, subsurface heating
using hydrogen sulfide may produce a combustion product stream
having a temperature from about 500.degree. C. to about
2000.degree. C. to heat the steam which heats a portion of the
hydrocarbon layer. In contrast, conventional steam injection
methods may produce steam temperatures of about 290.degree. C. for
heating the hydrocarbon layer, where the temperature of the steam
decreases along the length of the wellbore as the distance
increases from the injection point of the steam.
[0063] Subsurface heating of steam supplied to an injection well
may inhibit water condensation along the length of the injection
well. Inhibiting water condensation in the injection well may
enhance heating and allow more uniform heating of the hydrocarbon
layer. Subsurface heating of steam may lessen the amount of steam
required to be injected to heat the hydrocarbon layer, for example
by lessening the amount of premature steam condensation. In some
embodiments, water re-cycling facilities are reduced due to more
efficient use of the steam. Subsurface heating of steam may reduce
or eliminate the requirement for hydrocarbon gases at the well site
as an energy source, thereby allowing additional hydrocarbon gases
to be sold for commercial and/or residential energy sources.
[0064] The heated portion of the steam may be used to sustain the
combustion of the mixture of the fuel stream comprising hydrogen
sulfide and the oxidant stream in the wellbore downstream of the
transfer of heat from the combustion to the steam. The steam may be
heated to a temperature at or above the auto-ignition temperature
of the mixture of the fuel stream and the oxidant stream by
transfer of heat from the combustion to the steam. The flow of the
heated steam may be directed into the wellbore (downstream from the
wellhead) and heat may be transferred from the heated steam to a
mixture of the fuel stream comprising hydrogen sulfide and the
oxidant stream downstream of the transfer of heat from the
combustion to the steam, where the heat transferred from the heated
steam to the downstream mixture of the fuel stream and the oxidant
stream is sufficient to heat the mixture to a temperature at or
above the auto-ignition temperature of the mixture so that the
mixture combusts to provide further heat to the steam in the
wellbore.
[0065] The steam in the wellbore or exiting the wellbore into the
hydrocarbon formation may be heated by contact with at least a
portion of the combustion by-products stream. The combustion
by-products stream may directly transfer heat from the combustion
to a least a portion of the steam and the combustion by-products
stream may generate a heat of solution upon being mixed with the
steam or water, particularly if the combustion by-products stream
contains significant amounts of sulfur trioxide that may be
converted to sulfuric acid upon mixing with the steam/water. The
steam/water heated by the combustion by-products stream may
transfer heat to a portion of the hydrocarbon formation to provide
a driving force for mobilization of at least a portion of the
formation fluids.
[0066] Combustion by-products from surface facilities may be
introduced into steam being provided to a wellbore. Heat from the
heaters may provide heat to the combustion by-products from the
surface facilities to facilitate driving such combustion
by-products into the hydrocarbon formation. The steam provided to
the wellbore may be initially heated using combustion by-products
from surface facilities. The steam provided to the one or more
wellbores may also include carbon dioxide, sulfur dioxide,
combustion by-products from surface facilities, or mixtures
thereof. In particular, carbon dioxide may be sequestered in the
hydrocarbon formation by injecting the carbon dioxide in a
wellbore, where heat from the combustion of the fuel stream
comprising hydrogen sulfide and the oxidant stream provides heat to
the injected carbon dioxide to facilitate driving the carbon
dioxide into the hydrocarbon formation.
[0067] 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.
[0068] 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.
[0069] 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.
[0070] 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.
[0071] 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.
[0072] The steam may be provided in a first portion of a wellbore,
for example a first conduit, and combustion of the mixture of the
fuel stream comprising hydrogen sulfide and the oxidant stream may
occur in a second portion of the wellbore, for example a heater
located in a second conduit. The second portion of the wellbore may
be in thermal communication with the first portion of the wellbore
so that heat from the combustion of the fuel stream and the oxidant
stream may be transferred from the second portion of the wellbore
to the water/steam flowing in the first portion of the wellbore.
The first portion of the wellbore may be in thermal communication
with a portion of the hydrocarbon formation so that heat from
heated water/steam may be transferred from the heated water/steam
to the portion of the hydrocarbon formation in thermal
communication with the first portion of the wellbore. The first
portion of the wellbore may be in thermal communication with the
hydrocarbon formation along the length of the wellbore. The first
portion of the wellbore may also be in thermal communication with
the hydrocarbon formation at the terminus of the wellbore in the
hydrocarbon formation, where the water/steam may be injected into
the hydrocarbon formation.
[0073] In some embodiments, the heater is positioned in an inner
portion of a wellbore. An outer portion of the wellbore may allow
addition of a stream that includes water (for example, a drive
fluid or a solvent) and/or heating of the stream as it is
introduced into the hydrocarbon containing formation. 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.
[0074] Fuel may be provided to one or more fuel conduits, where at
least one of the conduits provides a portion of the fuel comprising
hydrogen sulfide and at least one of the conduits provides another
fuel. The fuel may be provided to one or more fuel conduits in at
least one of the heaters 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.
[0075] Passing of the fluid (for example, a stream that includes
water) through the outer portion of the wellbore and into the
hydrocarbon containing formation may move or drive the formation
fluids to a production well. The fluid 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 fluid with the formation fluids may
lower the viscosity the formation fluids and promote movement of
the formation fluids towards one or more production wells.
[0076] Heat generated from the heater in the inner portion of the
wellbore may heat at least a portion the fluid passing through the
outer portion of the wellbore. Heat may also be generated by
contact or reaction of the combustion by-products produced from the
heater with the fluid passing through the outer portion of the
wellbore. The combustion by-products may move or drive the fluid in
the outer conduit into the hydrocarbon containing formation. In
some embodiments, combustion generates combustion by-products that
include sulfur dioxide. At least a portion of formation fluids in
the hydrocarbon containing formation may mix with the generated
sulfur dioxide to form a mixture.
[0077] In some embodiments, transferring heat to at least a portion
of the fluid passing through the outer portion may sustain
oxidation and heat along portions of the heater along the length of
the heater. Sustaining heat along a portion of the heater may
enhance stability of the heater at oxidation temperatures under all
operating conditions.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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.
[0082] 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.
[0083] 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.
[0084] 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.
[0085] 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.
[0086] 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.
[0087] 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.
[0088] 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.
[0089] 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.
[0090] 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.
[0091] 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.
[0092] 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.
[0093] 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.
[0094] 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.
[0095] 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.
[0096] 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.
[0097] FIG. 8 depicts a representation of an embodiment for
producing hydrocarbons from a hydrocarbon containing formation (for
example, a tar sands formation). Hydrocarbon layer 106 includes one
or more portions with heavy hydrocarbons. Hydrocarbon layer 106 may
be below overburden 180. Hydrocarbons may be produced from
hydrocarbon layer 106 using more than one process.
[0098] Hydrocarbons may be produced from a first portion of
hydrocarbon layer 106 using a steam injection process and/or other
drive process (for example, a carbon dioxide drive process). The
steam injection process may include steam drive, cyclic steam
injection, SAGD, or other process of steam injection into the
formation. A portion of hydrocarbon layer 106 may be treated using
heaters prior to the steam injection process. Heaters may be used
to increase the temperature and/or permeability of the portion of
hydrocarbon layer 106. Some hydrocarbons may be produced through
production well 108 by heating the hydrocarbon portion.
Alternatively, hydrocarbon layer 106 may not be heated prior to
steam injection. The production well 108 may be located at a depth
of 100, 200, 500, 1000, 1500, 2500, 5000, 10000, or 10500 meters.
The pattern and number of injection wells, heater wells and
production wells may be any number or geometry sufficient to
achieve production of formation fluids from a hydrocarbon
containing formation.
[0099] Injection well 102 may include heater 130 or a series of
heaters. The heaters 130 may be inserted in injection well 102
after some hydrocarbons have been produced from hydrocarbon layer
106. The injection well 102 may be located at a depth of below 100,
200, 500, 1000, 1500, 2500, 5000, or 10000 meters. Heating or
injecting drive fluids at shallow depths of a formation may allow
recovery of hydrocarbons that are not readily accessible through
conventional steam drive processes and/or thermal heating using
heaters. Heating or injecting drive fluids in a hydrocarbon
containing formation at shallow depths may also allow recovery of
hydrocarbons that are not readily accessible through conventional
hydrocarbon recovery methods.
[0100] The injection well 102 may be fabricated from materials
known in the art to be resistant to sulfur oxides. For example,
injection well 102 may be made from Hastelloy.RTM. C276, alloy 230,
alloy 800H, alloy 370H, nickel/copper/iron alloys, or
cobalt-chromium alloys.
[0101] Water 162 (for example, steam and/or hot water) may be
injected into injection well 102. Water may be injected at
temperatures of at least 200.degree. C., at least 225.degree. C.,
at least 250.degree. C., or at least 260.degree. C. and pressures
ranging from about 1 MPa to about 15 MPa. Fuel stream 152 and
oxidant stream 156 enter heaters 130. Combustion of a fuel/oxidant
mixture in heaters 130 may heat water 162 and/or heat a portion of
hydrocarbon containing layer 106. Heat from water 162 may be
sufficient to auto ignite the fuel/oxidant mixture.
[0102] Heat produced during combustion of the fuel/oxidant mixture
in combustion conduit 158 transfers heat to water 162. Heated water
162 may flow into hydrocarbon layer 106 through openings 104. Heat
and/or injectivity of steam, combustion gases and/or hydrogen
sulfide may mobilize formation fluid in hydrocarbon layer 106
towards production wells. The ability to heat water 162 in the
formation may allow for expanded and/or more uniform heating of
hydrocarbon layer 106.
[0103] Heat from combustion and/or heated water 162 forms a first
heated zone. Hydrocarbons in hydrocarbon layer 106 may be mobilized
by the heat and produced from production well 108.
[0104] Combustion of hydrogen sulfide/oxidant mixture produces a
combustion by-products stream. The combustion by-products stream
may include sulfur oxides such as sulfur trioxide and/or sulfur
dioxide. Contacting (for example, mixing, solvating, and/or
dissolving) of at least a portion of the sulfur oxides in water 162
may heat the water in well 102 and/or hydrocarbon layer 106 to form
a second heated zone. The second heated zone may heat a portion of
the hydrocarbon layer 106 proximate the end of injection well 102
and/or extend into hydrocarbon layer 106. Due to the heat transfer
and more uniform heating of hydrocarbon layer 106, an increased
amount of hydrocarbons may be produced per volume as compared to
conventional drive fluid processes. The first and second heated
zones may overlap.
[0105] In some embodiments, the second heated zone is a substantial
distance from well 102. For example, combustion by-products may
drive the steam into the formation. As steam condenses, the sulfur
oxides in the combustion by-products react with the condensed water
to generate heat from the formation of sulfuric acid. The generated
heat may provide heat to the formation to sufficiently mobilize
hydrocarbons towards production well 108. The combination of
subsurface steam heating in combination with latent heating
(heating after the steam condenses) may facilitate recovery of
hydrocarbons from the formation. The combination of sensible heat
for all introduced components and latent heat may reduce energy
and/or heating requirements for producing hydrocarbons from the
formation as compared to the energy and/or heating requirements for
conventional hydrocarbon recovery processes.
[0106] The hydrocarbon formation may contain limestone. As the
sulfur oxides contact the formation in the presence of water, the
limestone reacts with the sulfur oxides and produces carbon
dioxide. The carbon dioxide may serve as an additional drive fluid
to push the fluids towards production well 108.
[0107] The sulfur oxides may react with aromatic hydrocarbons in
the formation fluids and form sulfonates. The formation of in-situ
sulfonates may facilitate moving hydrocarbons towards one or more
production wells.
[0108] Formation fluids 110 produced from production well 108 may
be treated in a surface facility (for example, in surface
facilities described with respect to FIG. 2) to form a gas stream
and a liquid stream. In some embodiments, the produced hydrocarbons
have an API gravity of at most 15, at most 10, at most 8, or at
most 6. The gas stream may include hydrogen sulfide, sulfur
dioxide, hydrocarbon gases and/or carbon dioxide. In some
embodiments, the sulfur dioxide is separated from the formation
fluids using a regenerable process (for example, as described in
FIG. 2). At least a portion of the sulfur dioxide may be introduced
into the outer conduit 164 and/or into the hydrocarbon containing
formation. In some embodiments, formation fluids that include least
a portion of the sulfur dioxide from the hydrocarbon containing
formation are produced and separated from the formation fluids. At
least a portion of the separated sulfur dioxide may be provided to
the hydrocarbon containing formation and/or at least one of the
flameless distributed combustors.
[0109] All or a portion of the gas stream 116 may be transferred to
fuel stream 152 and combusted in heater 130. In some embodiments,
fuel stream 152 includes sulfur dioxide. In the presence of oxidant
in heater 130, at least a portion of the sulfur dioxide may be
converted to sulfur trioxide and subsequently converted to sulfuric
acid in the formation. In some embodiments, at least a portion of
sulfur dioxide enters the formation. By recycling the sulfur
dioxide, a majority of sulfur emissions produced from the formation
and/or from surface facilities are abated, thus reducing emissions
as compared to emissions (for example, carbon dioxide) generated by
combustion of fossil fuels make steam for steam flooding.
[0110] In some embodiments, water 162 includes one or more
surfactants and/or one or more foaming agents. Surfactants include
thermally stable surfactants (for example, sulfates, sulfonates,
alkyl benzene sulfonates, ethoxylated sulfates, and/or phosphates).
The use of foaming agents and/or surfactants may change the surface
tension between the hydrocarbons and the formation to allow the
hydrocarbons to be mobilized towards production well 108. In some
embodiments, water 162 includes an antifoaming agent. The
antifoaming agent may inhibit foaming of the formations fluids when
carbon dioxide and surfactants are present.
[0111] In some embodiments, water 162 introduced into hydrocarbon
layer 106 includes hydrogen sulfide and or hydrogen. The hydrogen
sulfide and/or hydrogen may solvate, dilute, and/or hydrogenate a
portion of the heavy hydrocarbons to form a mixture that may
mobilize formation fluid toward production well 108. Formation of
the mixture may increase production of hydrocarbons in hydrocarbon
layer 106. Solubilization, dilution, and/or hydrogenation of a
portion of the heavy hydrocarbons may allow an increase in the
amount of hydrocarbons produced from the hydrocarbon layer. The
solvents and/or hydrogen sulfide may be separated from the mixture
and injected with water 162 or used in other processes. For
example, hydrogen sulfide may be separated from the mixture and
combusted to heat water. In some embodiments, heat from
hydrogenation of hydrocarbons transfers to a portion of hydrocarbon
layer 106 and/or to water 162.
[0112] In some embodiments, heater 130 or a series of heaters are
positioned in injection well 102. Water 162, heated to at least
300.degree. C., or at least 500.degree. C., and pressurized to
pressures ranging from 1 MPa to 15 MPa, may be introduced into well
102 and transfer heat to hydrocarbon layer 106. A portion of water
162 may enter hydrocarbon layer 106 through openings 104. Water 162
may cool as it flows through outer conduit 164. Heaters positioned
downstream of the wellhead may be ignited to heat water 162 as it
flows through outer conduit 164. Heaters may heat water 162 to a
temperature sufficient to heat hydrocarbon layer 106 (for example,
to temperatures ranging from about 200.degree. C. to about
500.degree. C.). Formation fluids may be moved by the heat and/or
water 162 towards production well 108. Temperatures in various
portions of well 102 may be monitored. Heaters may be ignited at
pre-determined temperatures in well 102. In some embodiments, water
162 is heated subsurface to form super heated steam.
[0113] In some embodiments, subsurface heating of water 162
increases a volume of a hydrocarbon containing layer to be heated
as compared to heating using conventional steam injection methods.
Subsurface heating allows the use of substantially liquid water
and/or low pressure steam as a drive fluid instead of having to
heat or pressurize steam at or above formation pressures prior to
injection into the hydrocarbon containing formation. Subsurface
heating of water in an injection well may create a steam reboiler
along the length of the flameless distributed oxidizer. The ability
to substantially heat the drive fluid (for example, steam) along
the length of the heater may allow the hydrocarbon layer to be
heated in a more uniform manner as compared to a system using a
surface heated drive fluid. More uniform heating may allow
production wells to be positioned at greater distances from the
injection well as compared to conventional steam injection
processes.
[0114] In some embodiments, subsurface heating of water changes the
heat flux profile of the system as compared to conventional drive
fluid injection processes. FIG. 9 depicts a schematic of a heat
flux profile of an embodiment of a conventional steam injection
process. The injected steam in a conventional steam injection
process flows to the end of injection well 102, the steam cools,
and forms condensate as it moves towards portions of the well
farthest from the injection site. Cooling of the steam decreases
the amount of heat that is transferred to the hydrocarbon layer as
indicated by the arrow length. Thus, heat transfer may be greatest
at sections closest to wellhead relative to the end portions of the
well.
[0115] In some embodiments, a method of treating a hydrocarbon
containing formation, includes providing steam to at least a
portion of a hydrocarbon containing formation from a plurality of
locations in a wellbore, where the steam is hotter than a
temperature of the portion of the hydrocarbon containing formation;
and heating the steam in the wellbore by combusting at least a
portion of a mixture that includes fuel and oxidant in the
wellbore, where the fuel includes hydrogen sulfide. Heat from the
combustion transfers to the steam; and the steam is heated such
that the steam provided to the portion of the hydrocarbon
containing formation at a first location in the wellbore is hotter
than steam provided at a second location in the wellbore; and the
first location is further from a surface of the formation than the
second location along the length of the wellbore. In some
embodiments, combustion generates a combustion by-products stream
and at least a portion of the combustion by-products stream is
contacted with a portion of the water in a portion of the
hydrocarbon containing formation that is downstream of the
formation surface, along the length of the wellbore, from the
transferred heat portion. In some embodiments, at least a portion
of the heat is transferred to at least a portion the hydrocarbon
containing formation; and at least a portion of formation fluids
are mobilized in the heated portion.
[0116] FIGS. 10A and 10B depict schematics of a heat flux profile
of an embodiment of subsurface heating of steam using heaters 130
in a horizontal injection well 102. As shown in FIG. 10A, longer
arrows indicate more heat is generated at the downstream portion of
the well than at the upstream portion of the well when using
heaters 130 to heat water in the formation. As shown, steam 162 is
heated such that the steam provided to the layer at the downstream
portion of the wellbore is hotter than steam provided to the
hydrocarbon containing formation near the upstream portion of the
formation. By controlling where the hotter portion is along the
length of the wellbore heat may be transferred in a uniform manner
to the formation, thus the heat flux, hot spots and/or cold spots
along the length of the wellbore may be controlled. Hydrocarbons
mobilized by the heat and/or steam from injection well 102 are
produced from production well 108. In some embodiments, the
downstream portion of the wellbore is proximate to a portion of
formation having more hydrocarbons per volume (richer in
hydrocarbons), as compared to the first location, thus allowing
heat to transfer to hydrocarbons that may be more difficult to
produce using conventional steam drive processes. In some
embodiments, production well 108 may include openings to allow the
hydrocarbons to flow into the well.
[0117] As shown in FIG. 10B, a shape of the heat flux profile may
be parabolic. Heated water enters injection well 102 and heats an
upstream portion of the well. As the water cools the heat profile
diminishes. As the water cools, the heaters in well 102 are ignited
to reheat the water. Other heat flux profiles, such as a
substantially constant heat flux, may be obtained by adjusting the
portion of the openings and/or heaters.
[0118] By keeping temperatures of the steam along the length of the
wellbore at a constant temperature, the fuel and oxidant
temperatures along the length of the wellbore may be buffered, thus
inhibiting temperature fluctuations (for example, formation of hot
spots and/or cold spots) along the length of the heater. Inhibiting
temperature fluctuations may sustain and/or enhance oxidation along
the length of the heater. Such consistent heating of the wellbore
may allow heat to transfer uniformly to the formation thus
facilitating mobilization and/or production of formation fluids
from the hydrocarbon containing formation.
[0119] Uniform transfer of heat to hydrocarbon layer 106 from
injection well 102 using heaters 130 may facilitate mobilization of
more hydrocarbons towards production well 108. The change in heat
flux profile and more uniform heating of the hydrocarbon layer may
allow production well 108 to be positioned at distances greater
than those used for conventional drive fluid injection, thus
allowing hydrocarbons in less accessible areas to be produced.
[0120] In some embodiments, production of hydrocarbons from a
hydrocarbon containing layer is enhanced by heating an area with a
hydrogen sulfide fueled heater located in a well proximate the end
of one or more horizontal steam injection wells. The heat provided
by the hydrogen sulfide fueled heater may enhance production of
hydrocarbons from the hydrocarbon layer.
[0121] In some embodiments, a method of treating a hydrocarbon
containing formation, includes: 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 that includes hydrogen sulfide and oxidant
in one or more flameless distributed combustors positioned in one
or more substantially vertical wellbores to generate heat, where 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; allowing a portion of the generated heat to
transfer 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. In
some embodiments, the generated heat transfers to the portion by
conduction, convention or by heat of solution, wherein the
generated heat transfers to the portion by convection.
[0122] In some embodiments, a portion of the steam is heated by
combusting at least a portion of the mixture in one or more
flameless distributed combustors positioned in at least one of the
substantially horizontal steam injection wells. In some
embodiments, a portion of the steam is heated by combusting at
least a portion of the mixture in one or more burners positioned in
at least one of the substantially horizontal steam injection
wells.
[0123] The steam transfers heat to at least a portion of the
hydrocarbon containing formation. At least a portion of the steam
may drive at least a portion of the formation fluids towards one or
more production wells. Formation fluids may be produced from a
volume between at least one of the substantially vertical heater
wells and at least one of the substantially horizontal steam
injection wells. In some embodiments, the hydrocarbon formation is
heated prior to providing the water. In some embodiments, at least
a portion of the combustion by-products is provided to the
formation. At least a portion of the combustion by-products and/or
at least a portion of the steam into the formation provide a
driving force for mobilization of at least a portion of the
formation fluids.
[0124] In some embodiments, the combustion by-products stream
include sulfur oxides, and at least a portion of the combustion
by-products steam is provided to the hydrocarbon containing
formation such that at least a portion of the steam and a portion
of the sulfur oxides mixes with water in the formation to generate
heat of solution and at least a portion of the solution heat is
transferred to a portion of the hydrocarbon containing
formation.
[0125] FIG. 11 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.
[0126] 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.
* * * * *