Note: Descriptions are shown in the official language in which they were submitted.
CA 02871784 2014-11-18
SYSTEMS, METHODS AND PROCESSES FOR USE IN TREATING SUBSURFACE FORMATIONS
BACKGROUND
I. Field of the Invention
The present invention relates generally to methods and systems for production
of hydrocarbons,
hydrogen, and/or other products from various subsurface formations such as
hydrocarbon containing formations.
2. Description of Related Art
Hydrocarbons obtained from subterranean formations are often used as energy
resources, as feedstocks,
and as consumer products. Concerns over depletion of available hydrocarbon
resources and concerns over
declining overall quality of produced hydrocarbons have led to development of
processes for more efficient
recovery, processing and/or use of available hydrocarbon resources. In situ
processes may be used to remove
hydrocarbon materials from subterranean formations. Chemical and/or physical
properties of hydrocarbon
material in a subterranean formation may need to be changed to allow
hydrocarbon material to be more easily
removed from the subterranean formation. The chemical and physical changes may
include in situ reactions that
produce removable fluids, composition changes, solubility changes, density
changes, phase changes, and/or
viscosity changes of the hydrocarbon material in the formation. A fluid may
be, but is not limited to, a gas, a
liquid, an emulsion, a slurry, and/or a stream of solid particles that has
flow characteristics similar to liquid
flow.
A wellbore may be formed in a formation. In some embodiments wellbores may be
formed using
reverse circulation drilling methods. Reverse circulation methods are
suggested, for example, in published U.S.
Patent Application Publication No. 2004-0079553 to Livingstone, and U.S.
Patent Nos. 6,854,534 to
Livingstone; 6,892,829 to Livingstone, 7,090,018 to Livingstone; and 4,823,890
to Lang. Reverse circulation
methods generally involve circulating a drilling fluid to a drilling bit
through an annulus between concentric
tubulars to the borehole in the vicinity of the drill bit, and then through
openings in the drill bit and to the
surface through the center of the concentric tubulars, with cuttings from the
drilling being carried to the surface
with the drilling fluid rising through the center tubular. A wiper or shroud
may be provided above the drill bit
and above a point where the drilling fluid exits the annulus to prevent the
drilling fluid from mixing with
formation fluids. The drilling fluids may be, but is not limited to, air,
water, brines and/or conventional drilling
fluids.
In some embodiments, a casing or other pipe system may be placed or formed in
a wellbore. U.S.
Patent No. 4,572,299 issued to Van Egmond et al., describes spooling an
electric heater into a well. In some
embodiments, components of a piping system may be welded together. Quality of
formed wells may be
monitored by various techniques. In some embodiments, quality of welds may be
inspected by a hybrid
electromagnetic acoustic transmission technique known as EMAT. EMAT is
described in U.S. Patent Nos.
5,652,389 to Schaps et al.; 5,760,307 to Latimer et al.; 5,777,229 to Geier et
al.; and 6, 155,117 to Stevens et al.,
each of which is incorporated by reference as if fully set forth herein.
In some embodiments, an expandable tubular may be used in a wellbore.
Expandable tubulars are
described in U.S. Patent Nos. 5,366,012 to Lohbeck, and 6,354,373 to Vercaemer
et al.
Heaters may be placed in wellbores to beat a formation during an in situ
process. Examples of in situ
processes utilizing downhole heaters are illustrated in U.S. Patent Nos.
2,634,961 to Ljungstrom; 2,732,195 to
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Ljungstrom; 2,780,450 to Ljungstrom; 2,789,805 to Ljungstrom; 2,923,535 to
Ljungstrom; and 4,886,118 to
Van Meurs et al.
Application of heat to oil shale formations is described in U.S. Patent Nos.
2,923,535 to Ljungstrom
and 4,886,118 to Van Meurs et al. Heat may be applied to the oil shale
formation to pyrolyze kerogen in the oil
shale formation. The heat may also fracture the formation to increase
permeability of the formation. The
increased permeability may allow formation fluid to travel to a production
well where the fluid is removed from
the oil shale formation. In some processes disclosed by Ljungstrom, for
example, an oxygen containing gaseous
medium is introduced to a permeable stratum, preferably while still hot from a
preheating step, to initiate
combustion.
A heat source may be used to heat a subterranean formation. Electric heaters
may be used to heat the
subterranean formation by radiation and/or conduction. An electric heater may
resistively heat an element.
U.S. Patent No. 2,548,360 to Germain, describes an electric heating element
placed in a viscous oil in a
wellbore. The heater element beats and thins the oil to allow the oil to be
pumped from the wellbore. U.S. Patent
No. 4, 716,960 to Eastlund et al. describes electrically heating tubing of a
petroleum well by passing a relatively
low voltage current through the tubing to prevent formation of solids. U.S.
Patent No. 5,065,818 to
Van Egmond, describes an electric heating element that is cemented into a well
borehole without a casing
surrounding the heating element.
U.S. Patent No. 6,023,554 to Vinegar et al., describes an electric heating
element that is positioned in a
casing. The heating element generates radiant energy that heats the casing. A
granular solid fill material may be
placed between the casing and the formation. The casing may conductively heat
the fill material, which in turn
conductively heats the formation.
U.S. Patent No. 4,570,715 to Van Meurs et al., describes an electric heating
element. The heating
element has an electrically conductive core, a surrounding layer of insulating
material, and a surrounding
metallic sheath. The conductive core may have a relatively low resistance at
high temperatures. The insulating
material may have electrical resistance, compressive strength, and heat
conductivity properties that are relatively
high at high temperatures. The insulating layer may inhibit arcing from the
core to the metallic sheath. The
metallic sheath may have tensile strength and creep resistance properties that
are relatively high at high
temperatures.
U.S. Patent No. 5,060,287 to Van Egmond, describes an electrical heating
element having a copper-
nickel alloy core.
Obtaining permeability in an oil shale formation between injection and
production wells tends to be
difficult because oil shale is often substantially impermeable. Many methods
have attempted to link injection
and production wells. These methods include: hydraulic fracturing such as
methods investigated by Dow
Chemical and Laramie Energy Research Center; electrical fracturing by methods
investigated by Laramie
Energy Research Center; acid leaching of limestone cavities by methods
investigated by Dow Chemical; steam
injection into permeable nahcolite zones to dissolve the nahcolite by methods
investigated by Shell Oil and
Equity Oil; fracturing with chemical explosives by methods investigated by
Talley Energy Systems; fracturing
with nuclear explosives by methods investigated by Project Bronco; and
combinations of these methods. Many
of these methods, however, have relatively high operating costs and Jack
sufficient injection capacity.
Large deposits of heavy hydrocarbons (heavy oil and/or tar) contained in
relatively permeable
formations (for example in tar sands) are found in North America, South
America, Africa, and Asia. Tar can be
surface-mined and upgraded to lighter hydrocarbons such as crude oil, naphtha,
kerosene, and/or gasoil. Surface
milling processes
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may further separate the bitumen from sand. The separated bitumen may be
converted to light hydrocarbons
using conventional refinery methods. Mining and upgrading tar sand is usually
substantially more expensive
than producing lighter hydrocarbons from conventional oil reservoirs.
In situ production of hydrocarbons from tar sand may be accomplished by
heating and/or injecting a
gas into the formation. U.S. Patent Nos. 5,211,230 to Ostapovich et al. and
5,339,897 to Leaute, describe a
horizontal production well located in an oil-bearing reservoir. A vertical
conduit may be used to inject an
oxidant gas into the reservoir for in situ combustion.
U.S. Patent No. 2,780,450 to Ljungstrom describes heating bituminous
geological formations in situ to
convert or crack a liquid tar-like substance into oils and gases.
U.S. Patent No. 4,597,441 to Ware et al., describes contacting oil, heat, and
hydrogen simultaneously
in a reservoir. Hydrogenation may enhance recovery of oil from the reservoir.
U.S. Patent No. 5,046,559 to Glandt and 5,060,726 to Glandt et al., describe
preheating a portion of a
tar sand formation between an injector well and a producer well. Steam may be
injected from the injector well
into the formation to produce hydrocarbons at the producer well.
As outlined above, there has been a significant amount of effort to develop
methods and systems to
economically produce hydrocarbons, hydrogen, and/or other products from
hydrocarbon containing formations.
At present, however, there are still many hydrocarbon containing formations
from which hydrocarbons,
hydrogen, and/or other products cannot be economically produced. Thus, there
is still a need for improved
methods and systems for production of hydrocarbons, hydrogen, and/or other
products from various
hydrocarbon containing formations.
SUMMARY
Embodiments described herein generally relate to systems, methods, and heaters
for treating a
subsurface formation. Embodiments described herein also generally relate to
heaters that have novel
components therein. Such heaters can be obtained by using the systems and
methods described herein.
In certain embodiments, the invention provides one or more systems, methods,
and/or heaters. In some
embodiments, the systems, methods, and/or heaters are used for treating a
subsurface formation.
In certain embodiments, the invention provides a system for heating a
hydrocarbon containing
formation, comprising: a conduit located in an opening in the formation, the
conduit comprising ferromagnetic
material; an electrical conductor positioned inside the conduit, and
electrically coup led to the conduit at or near
an end portion of the conduit so that the electrical conductor and the conduit
are electrically coup led in series
and electrical current flows in the electrical conductor in a substantially
opposite direction to electrical current
flow in the conduit during application of electrical current to the system;
wherein, during application of
electrical current to the system, the flow of electrons is substantially
confined to the inside of the conduit by the
electromagnetic field generated from electrical current flow in the electrical
conductor so that the outside
surface of the conduit is at or near substantially zero potential at 25 C; and
the conduit is configured to generate
heat and heat the formation during application of electrical current to the
system.
In certain embodiments, the invention provides a method of heating a
subsurface formation,
comprising: providing a conduit to an opening in the formation, wherein the
conduit comprises ferromagnetic
material; positioning an electrical conductor inside the conduit; providing
the conduit so that the conduit is
electrically coupled at or near an end portion of the conduit so that the
electrical conductor and the conduit are
electrically
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coupled in series and electrical current flows in the electrical conductor in
a substantially opposite direction to
electrical current flow in the conduit during application of electrical
current to the system; applying electrical current
to the conduit to generate heat in the conduit, wherein, during application of
electrical current, the flow of electrons
is substantially confined to the inside of the conduit by the magnetic field
generated from electrical current flow in
the electrical conductor so that the outside surface of the conduit is at or
near substantially zero potential at 25 C;
and allowing heat to transfer from the conduit to at least a portion of the
formation.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
nahcolite, the method comprising: providing a first fluid to a portion of the
formation through at least two injection
wells; producing a second fluid from the portion through at least one
injection well until at least two injection wells
are interconnected such that fluid can flow between the two injection wells,
wherein the second fluid includes at
least some nahcolite dissolved in the first fluid; injecting the first fluid
through one of the interconnected injection
wells; producing the second fluid from at least one of the interconnected
injection wells; providing heat from one or
more heaters to the formation to heat the formation; and producing hydrocarbon
fluids from the formation.
In certain embodiments, the invention provides a method for treating an oil
shale formation, the method
comprising: providing a first fluid to a first portion of the formation;
producing a second fluid from the first portion,
wherein the second fluid includes at least some sodium bicarbonate dissolved
in the first fluid; providing heat from
one or more heat sources to heat a second portion of the formation; and using
heat from the second portion of the
formation to heat the second fluid to produce soda ash.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
nahcolite, the method comprising: providing a first fluid to a portion of the
formation; producing a second fluid
from the portion to cause selective vertical shifting of at least some of the
portion of the formation, the second fluid
including at least some nahcolite dissolved in the first fluid; providing heat
from one or more heaters to the
formation to heat at least a portion of the formation that has been vertically
shifted; and producing hydrocarbon
fluids from the formation.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
nahcolite, the method comprising: providing a first fluid comprising steam to
a portion of the formation, wherein the
first fluid is at a temperature below a pyrolysis temperature of hydrocarbons
in the portion of the formation;
producing a second fluid from the portion, wherein the second fluid comprises
nahcolite; providing heat from one or
more heaters to the formation to heat the formation; and producing hydrocarbon
fluids from the formation.
In certain embodiments, the invention provides a method for producing one or
more crude products,
comprising: producing formation fluid from a subsurface in situ heat treatment
process; separating the formation
fluid to produce a liquid stream and a gas stream; providing at least a
portion of the liquid stream to a nanofiltration
system to produce a retentate and a permeate, wherein the retentate comprises
clogging compositions; and
processing the permeate in one or more of processing units downstream of the
nanofiltration system to form one or
more crude products.
In certain embodiments, the invention provides a system for treating an in
situ heat treatment fluid,
comprising: a production well located in a formation, the production well
configured to produce a formation fluid,
wherein the formation fluid is produced using an in situ heat treatment
process; a separation unit, the separation unit
configured receive the formation fluid from the production well and the
separation unit configured to separate the
formation fluid into a liquid stream and a gas stream; a nanofiltration system
configured to receive the liquid stream
and the nanofiltration system configured to separate the liquid stream into a
retentate and a permeate.
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In certain embodiments, the invention provides a method, comprising: producing
formation fluid from a
subsurface in situ heat treatment process; separating the formation fluid to
produce a liquid stream and a gas stream;
providing at least a portion of the liquid stream to a hydrotreating unit; and
removing of at least a portion of selected
in situ heat treatment clogging compositions in the liquid stream to produce a
hydrotreated liquid stream by
hydrotreating at least a portion of the liquid stream at conditions sufficient
to remove the selected in situ heat
treatment clogging compositions.
In certain embodiments, the invention provides a transportation fuel, wherein
the transportation fuel is made
by a method comprising: producing formation fluid from a subsurface in situ
heat treatment process; separating the
formation fluid to produce a liquid stream and a gas stream; providing at
least a portion of the liquid stream to a
hydrotreating unit; removing of at least a portion of selected in situ heat
treatment clogging compositions in the
liquid stream to produce a hydrotreated liquid stream by hydrotreating at
least a portion of the liquid stream at
conditions sufficient to remove the selected in situ heat treatment clogging
compositions; and blending one or more
of the crude products with other components to make transportation fuel.
In certain embodiments, the invention provides a method for producing
alkylated hydrocarbons,
comprising: producing formation fluid from a subsurface in situ heat treatment
process; separating the formation
fluid to produce a liquid stream and a first gas stream, wherein the first gas
stream comprises olefins; fractionating
the liquid stream to produce at least a second gas stream comprising
hydrocarbons having a carbon number of at
least 3, and introducing the first gas stream and the second gas stream into
an alkylation unit to produce alkylated
hydrocarbons, wherein at least a portion of the olefins in the first gas
stream enhance alkylation.
In certain embodiments, the invention provides a method of producing alkylated
hydrocarbons, comprising:
producing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce
a liquid stream; catalytically cracking at least a portion of the liquid
stream in a first catalytic cracking system to
produce a crude product; separating at least a portion of the crude product
into one or more hydrocarbon streams,
wherein at least one of the hydrocarbon streams is a gasoline hydrocarbons
stream; catalytically cracking at least a
portion of the gasoline hydrocarbons stream by contacting the gasoline
hydrocarbon stream with a catalytic cracking
catalyst in a second catalytic cracking system to produce a crude olefin
stream; and introducing at least a portion of
the crude olefin stream into an alkylation unit to produce one or more
alkylated hydrocarbons.
In certain embodiments, the invention provides a method for producing a crude
product, comprising:
producing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce
a liquid stream and a first gas stream, wherein the first gas stream comprises
olefins; fractionating the liquid stream
to produce one or more crude products, wherein at least one of the crude
products has a boiling range distribution
from 38 C and 343 C as determined by ASTM Method D5307; and catalytically
cracking the crude product having
the boiling range distribution from 38 C and 343 C to produce one or more
additional crude products, wherein at
least one of the additional crude products is a second gas stream, at the gas
stream has a boiling point of at most 38
C at 0.101 MPa.
In certain embodiments, the invention provides a method for producing
hydrocarbons, comprising:
producing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce
a liquid stream; catalytically cracking the liquid stream in a first catalytic
cracking system by contacting the liquid
stream with a catalytic cracking catalyst to produce a crude product stream
and a spent catalytic cracking catalyst;
regenerating the spent catalytic cracking catalyst to produce a regenerated
cracking catalyst; catalytically cracking a
gasoline hydrocarbons stream in a second catalytic cracking system by
contacting the gasoline hydrocarbons stream
with the regenerated catalytic cracking catalyst to produce a crude olefin
stream comprising hydrocarbons having a
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carbon number of at least 2 and a used regenerated cracking catalyst; and
separating at least some olefins from the
crude olefin stream, wherein the olefins have a carbon number from 2 to 5; and
providing the used regenerated
cracking catalyst from the second catalytic cracking system to the first
catalytic cracking system.
In certain embodiments, the invention provides a system for treating a tar
sands formation, comprising: a
plurality of heaters located in the formation, wherein the heaters include at
least partially horizontal heating sections
at least partially in a hydrocarbon layer of the formation, the heating
sections being at least partially arranged in a
pattern in the hydrocarbon layer, and the heaters being configured to provide
heat to the hydrocarbon layer, the
provided heat creating a plurality of drainage paths for mobilized fluids, at
least two of the drainage paths
converging; and a production well located to collect and produce mobilized
fluids from at least one of the converged
drainage paths in the hydrocarbon layer.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a
plurality of heaters located in the
formation, wherein the heaters include at least partially horizontal heating
sections at least partially in a hydrocarbon
layer of the formation, the heating sections being at least partially arranged
in a pattern in the hydrocarbon layer, and
the heaters being configured to provide heat to the hydrocarbon layer; wherein
the provided heat creates a plurality
of drainage paths for mobilized fluids, at least two of the drainage paths
converging; allowing at least some of the
mobilized fluids from the formation to flow to the production well along at
least one of the converged drainage
paths; and producing at least some of the mobilized fluids through the
production well.
In certain embodiments, the invention provides a system for treating a
hydrocarbon containing formation,
comprising: a steam and electricity cogeneration facility; at least one
injection well located in a first portion of the
formation, the injection well configured to provide steam from the steam and
electricity cogeneration facility to the
first portion of the formation; at least one production well located in the
first portion of the formation, the production
well configured to produce first hydrocarbons; at least one electrical heater
located in the second portion of the
formation, at least one of the electrical heaters configured to be powered by
electricity from the steam and electricity
cogeneration facility; at least one production well located in the second
portion of the formation, the production well
configured to produce second hydrocarbons; and the steam and electricity
cogeneration facility configured to use the
first hydrocarbons and/or the second hydrocarbons to generate electricity.
In certain embodiments, the invention provides a method for treating a
hydrocarbon containing formation,
comprising: providing steam to a first portion of the formation; producing
first hydrocarbons from the first portion
of the formation; providing heat from one or more electrical heaters to a
second portion of the formation; allowing
the provided heat to transfer from the heaters to the second portion of the
formation; producing second hydrocarbons
from the second portion of the formation; and using the first hydrocarbons
and/or the second hydrocarbons in a
steam and electricity generation facility, wherein the facility provides steam
to the first portion of the formation and
electricity for at least some of the heaters.
In certain embodiments, the invention provides a method for treating a
hydrocarbon containing formation,
comprising: providing steam to a first portion of the formation; providing
heat from one or more electrical heaters to
the first portion of the formation; producing first hydrocarbons and/or second
hydrocarbons from the first portion of
the formation; providing heat from one or more electrical heaters to a second
portion of the formation; allowing the
provided heat to transfer from the heaters to the second portion of the
formation; producing second hydrocarbons
from the second portion of the formation; and using the first hydrocarbons
and/or the second hydrocarbons in a
steam and electricity generation facility, wherein the facility provides steam
to the first portion of the formation and
electricity for at least some of the heaters.
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In certain embodiments, the invention provides a method for treating a
hydrocarbon containing formation,
comprising: providing steam to a first portion of the formation; producing
first hydrocarbons from the first portion
of the formation; providing heat from one or more electrical heaters to a
second portion of the formation; allowing
the provided heat to transfer from the heaters to the second portion of the
formation; providing steam to the second
portion of the formation; producing first hydrocarbons and/or second
hydrocarbons from the second portion of the
formation; and using the first hydrocarbons and/or the second hydrocarbons in
a steam and electricity generation
facility, wherein the facility provides steam to the first portion or the
second portion of the formation and electricity
for at least some of the heaters.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
dawsonite, the method comprising: providing heat from one or more heaters to
the formation to heat the formation;
producing hydrocarbon fluids from the formation; decomposing at least some
dawsonite in the formation with the
provided heat; providing a chelating agent to the formation to dissolve at
least some dawsonite decomposition
products; and producing the dissolved dawsonite decomposition products.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
dawsonite, the method comprising: providing heat from one or more heaters to
the formation to heat the formation;
producing hydrocarbon fluids from the formation; decomposing at least some
dawsonite in the formation with the
provided heat; providing a relatively basic fluid to the formation to dissolve
at least some dawsonite decomposition
products; and producing the dissolved dawsonite decomposition products.
In certain embodiments, the invention provides a method for producing
aluminum, the method comprising:
providing heat from one or more heaters to an oil shale formation to heat the
formation; producing hydrocarbon
fluids from the formation; decomposing at least some dawsonite in the
formation with the provided heat; providing a
chelating agent to the formation to dissolve at least some dawsonite
decomposition products; producing the
dissolved dawsonite decomposition products from the formation; separating
alumina from the dissolved dawsonite
decomposition products; using some of the produced hydrocarbon fluids to
produce electricity; and producing
aluminum metal from the alumina in a Hall process using the produced
electricity as power for the Hall process.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
dawsonite, the method comprising: assessing a dawsonite composition of one or
more zones in the formation;
providing heat from one or more heaters to the formation such that different
amounts of heat are provided to zones
with different dawsonite compositions; allowing the provided heat to transfer
from the heaters to the formation; and
producing fluids from the formation.
In certain embodiments, the invention provides a method for producing
aluminum, the method comprising:
assessing a dawsonite composition of one or more zones in the formation;
providing heat from one or more heaters
to the formation such that different amounts of heat are provided to zones
with different dawsonite compositions;
allowing the provided heat to transfer from the heaters to the formation; and
producing hydrocarbons from the
formation; decomposing at least some dawsonite in the formation with the
provided heat; providing a chelating agent
to the formation to dissolve at least some dawsonite decomposition products;
producing the dissolved dawsonite
decomposition products from the formation; separating alumina from the
dissolved dawsonite decomposition
products; using some of the produced hydrocarbon fluids to produce
electricity; and producing aluminum metal from
the alumina in a Hall process using the produced electricity as power for the
Hall process.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
nahcolite, the method comprising: providing a first fluid to a portion of the
formation; producing a second fluid
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from the portion, wherein the second fluid includes at least some nahcolite
dissolved in the first fluid; providing a
controlled amount of oxidant to the portion of the formation; and producing
hydrocarbon fluids from the formation.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
nahcolite, the method comprising: forming and maintaining a low temperature
zone around at least a portion of a
subsurface treatment area; providing a first fluid to a portion of the
subsurface treatment area; producing a second
fluid from the portion, wherein the second fluid includes at least some
nahcolite dissolved in the first fluid; providing
heat from one or more heaters to the subsurface treatment area to heat the
subsurface treatment area; providing a
controlled amount of oxidant to a portion of the subsurface treatment area;
and producing hydrocarbon fluids from
the subsurface treatment area.
In certain embodiments, the invention provides a method for treating an oil
shale formation comprising
nahcolite, the method comprising: forming a barrier around at least a portion
of a subsurface treatment area, the
barrier configured to inhibit fluid from exiting or entering the subsurface
treatment area; providing a first fluid to a
portion of the subsurface treatment area; producing a second fluid from the
portion, wherein the second fluid
includes at least some nahcolite dissolved in the first fluid; providing heat
from one or more heaters to the subsurface
treatment area to heat the subsurface treatment area; providing a controlled
amount of oxidant to a portion of the
subsurface treatment area; and producing hydrocarbon fluids from the
subsurface treatment area.
In certain embodiments, the invention provides a system for heating a
hydrocarbon containing formation,
comprising: a heater comprising an elongated ferromagnetic metal heater
section, wherein the heater is located in an
opening in a formation, the heater section being configured to heat the
hydrocarbon containing formation, and the
exposed ferromagnetic metal having a sulfidation rate that goes down with
increasing temperature of the heater,
when the heater is in a selected temperature range.
In certain embodiments, the invention provides a heater comprising a metal
section comprising:
ferromagnetic stainless steel having at least 2.0% cobalt by weight; and
wherein the composition of the exposed
metal section is such that the sulfidation rate of the metal section is at
most about 25 mils per year at a temperature
between about 800 C and about 880 C.
In certain embodiments, the invention provides a method for heating a
subsurface formation using a heater
comprising an elongated ferromagnetic metal heater section, wherein the
composition of the heater section is such
that sulfidation rate of the heater section decreases with increasing
temperature of the heater when the heater is at a
temperature in a selected temperature range.
In certain embodiments, the invention provides a method for heating a
subsurface formation using a heater
comprising an elongated ferromagnetic metal heater section comprising
stainless steel having at least 2.0% cobalt by
weight, and wherein the composition of the heater section is such that the
sulfidation rate of the heater section is less
than about 25 mils per year at a temperature between about 800 C to about 880
C.
In certain embodiments, the invention provides a method for treating a
hydrocarbon containing formation,
comprising: providing heat from one or more heaters located in a first section
of the formation; allowing some of the
heat to transfer from the first section to a second section of the formation,
the second section being adjacent to the
first section; producing at least some fluids from the second section of the
formation, wherein at least some of the
fluids produced in the second section comprise fluids initially in the first
section; and providing heat from one or
more heaters located in the second section of the formation after at least
some fluids have been produced from the
second section.
In certain embodiments, the invention provides a method for treating a
hydrocarbon containing formation,
comprising: providing heat from one or more heaters located in two or more
first sections of the formation; allowing
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some of the heat to transfer from the first sections to two or more second
sections of the formation; wherein the first
sections and the second sections are arranged in a checkerboard pattern, the
checkerboard pattern having each first
section substantially surrounded by one or more of the second sections and
each second section substantially
surrounded by one or more of the first sections; producing at least some
fluids from the second sections of the
formation, wherein at least some of the fluids produced in the second sections
comprise fluids initially in the first
sections; and providing heat from one or more heaters located in the second
sections of the formation after at least
some fluids have been produced from the second sections.
In certain embodiments, the invention provides a method for treating a
hydrocarbon containing formation,
comprising: treating a first zone of the formation at or near a center of a
treatment area; beginning treatment of a
plurality of zones of the formation at selected times after the treatment of
the first zone begins, the treatment of each
successively treated zone beginning at a selected time after treatment of the
previous zone begins; wherein each
successively treated zone is adjacent to the zone treated previously; wherein
the successive treatment of the zones
proceeds in an outward spiral sequence from the first zone so that the
treatment of the zones moves outwards
towards the boundary of the treatment area; wherein treatment of each of the
zones comprises: providing heat from
one or more heaters located in two or more first sections of the zone;
allowing some of the heat to transfer from the
first sections to two or more second sections of the zone; wherein the first
sections and the second sections are
arranged in a checkerboard pattern within the zone, the checkerboard pattern
having each first section substantially
surrounded by one or more of the second sections and each second section
substantially surrounded by one or more
of the first sections; producing at least some fluids from the second
sections, wherein at least some of the fluids
produced in the second sections comprise fluids initially in the first
sections; and providing heat from one or more
heaters located in the second sections after at least some fluids have been
produced from the second sections.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a
plurality of heaters located in the
formation; allowing the heat to transfer from the heaters so that at least a
portion of the formation reaches a
visbreaking temperature; maintaining a pressure in the formation below a
fracture pressure of the formation; and
producing at least some visbroken fluids from the formation.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
= providing heat to at least part of a hydrocarbon layer in the formation
from a plurality of heaters located in the
formation; allowing the heat to transfer from the heaters so that at least a
portion of the formation reaches a
visbreaking temperature; maintaining a pressure in the formation below a
fracture pressure of the formation while
allowing the portion of the formation heats to the visbreaking temperature;
reducing the pressure in the formation to
a selected pressure after the portion of the formation reaches the visbreaking
temperature; and producing fluids from
the formation.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a
plurality of heaters located in the
formation; allowing the heat to transfer from the heaters to at least a
portion of the formation; controlling conditions
in the formation so that water is recondensed in the formation in situ; and
producing fluids from the formation.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from
one or more heaters located in the
formation; creating an injection zone in the formation with the provided heat,
the injection zone having a
permeability sufficient enough to allow injection of a drive fluid into the
zone; providing the drive fluid into the
injection zone; and producing fluids from the formation.
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CA 02871784 2014-11-18
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing heat to a portion of a hydrocarbon layer in the formation from one
or more heaters located in the
formation; providing a drive fluid to a part of the portion of the formation
behind a heat front generated by the
heaters; and producing fluids the part of the formation behind the heat front.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing a drive fluid to a first portion of the formation to mobilize at
least some hydrocarbons in the first portion;
allowing at least some of the mobilized hydrocarbons to flow into a second
portion of the formation; providing heat
to the second portion the formation from one or more heaters located in the
formation; and producing at least some
hydrocarbons from the second portion of the formation.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing heat from one or more heaters to one or more karsted zones of the
tar sands formation; mobilizing
hydrocarbon fluids in the formation; and producing hydrocarbon fluids from the
formation.
In certain embodiments, the invention provides a method for treating a karsted
formation containing heavy
hydrocarbons, comprising: providing heat to at least part of one or more
karsted layers in the formation from one or
more heaters located in the karsted layers; allowing the provided heat to
reduce the viscosity of at least some
hydrocarbons in the karsted layers; and producing at least some hydrocarbons
from at least one of the karsted layers
of the formation.
In certain embodiments, the invention provides a method for treating a karsted
formation containing heavy
hydrocarbons, comprising: providing heat to at least part of one or more
karsted layers in the formation from one or
more heaters located in the karsted layers; allowing the provided heat to
reduce the viscosity of at least some
hydrocarbons in the karsted layers to get an injectivity in at least one of
the karsted layers sufficient to allow a drive
fluid to flow in the karsted layers; providing the drive fluid into at least
one of the karsted layers; and producing at
least some hydrocarbons from at least one of the karsted layers of the
formation.
In certain embodiments, the invention provides a method for treating a
formation containing dolomite and
hydrocarbons, comprising: providing heat at less than the decomposition
temperature of dolomite from one or more
heaters to at least a portion of the formation; mobilizing hydrocarbon fluids
in the formation; and producing
hydrocarbon fluids from the formation.
= In certain embodiments, the invention provides a method for treating a
karsted formation containing heavy
hydrocarbons, comprising: providing heat to at least part of one or more
karsted layers in the formation from one or
more heaters located in the karsted layers; allowing a temperature in at least
one of the karsted layers to reach a
decomposition temperature of dolomite in the formation; allowing the dolomite
to decompose; and producing at least
some hydrocarbons from at least one of the karsted layers of the formation.
In certain embodiments, the invention provides a method for treating a tar
sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from
one or more heaters located in the
formation; allowing the pressure to increase in an upper portion of the
formation to provide a gas cap in the upper
portion; and producing at least some hydrocarbons from a lower portion of the
formation.
In certain embodiments, the invention provides a method for treating a karsted
formation containing heavy
hydrocarbons, comprising: providing heat to at least part of one or more
karsted layers in the formation from one or
more heaters located in the karsted layers; allowing a temperature in at least
one of the karsted layers to reach a
decomposition temperature of dolomite in the formation; allowing the dolomite
to decompose and produce carbon
dioxide; maintaining the carbon dioxide in the formation to provide a gas cap
in an upper portion of at least one of
the karsted layers; and producing at least some hydrocarbons from at least one
of the karsted layers of the formation.
CA 02871784 2014-11-18
In certain embodiments, the invention provides a method for treating a tar
sands formation, the method
comprising the steps of: providing heat to a portion of a hydrocarbon layer in
the formation from one or more
heaters located in the formation; providing a drive fluid to a part of the
formation; and producing fluids from the
formation.
In certain embodiments, the invention provides a composition comprising: from
about percent 18 to about
22 percent by weight chromium; from about percent 12 to about 13 percent by
weight nickel; between about 3
percent by weight and about 10 percent by weight copper; from about 1 percent
to about 10 percent by weight
manganese; from about 0.3 percent to about 1 percent by weight silicon; from
about 0.5 percent to about 1.5 percent
by weight niobium; and from about 38 percent to about 63.5 percent by weight
iron.
In certain embodiments, the invention provides a composition comprising: from
about 18 percent to 22
percent by weight chromium; from about 10 percent to 14 percent by weight
nickel; from about 1 percent to 10
percent by weight copper; from about 0.5 percent to 1.5 percent by weight
niobium; from about 36 percent to 70.5
percent by weight iron; and precipitates of nanonitrides.
In certain embodiments, the invention provides a heater system comprising: a
heat generating element; and
a canister surrounding the heat generating system, wherein the canister is at
least partially made of a material
comprising: from about 18 percent to about 22 percent by weight chromium; from
about 10 percent to about 14
percent by weight nickel; from about 1 percent to 10 percent by weight copper;
from about 0.5 percent to 1.5 percent
by weight niobium; from about 36 percent to 70.5 percent by weight iron; and
precipitates of nanonitrides.
In certain embodiments, the invention provides a system for heating a
subterranean formation comprising a
tubular, the tubular at least partially made from a material comprising: from
about 18 percent to 22 percent by
weight chromium; from about 10 percent to 14 percent by weight nickel; from
about 1 percent to 10 percent by
weight copper; from about 0.5 percent to 1.5 percent by weight niobium; from
about 36 percent to 70.5 percent by
weight iron; and precipitates of nanonitrides.
In certain embodiments, the invention provides a composition comprising: about
11 percent to about 14
percent by weight Cr; about 6 percent to about 12 percent by weight Co; about
0.01 percent to about 0.15 percent by
weight C; about 0.1 percent to about 1.0 percent by weight Si; and about 65
percent to about 82 percent by weight
Fe.
In certain embodiments, the invention provides a heater comprising a metal
section comprising: iron,
cobalt, and carbon; wherein the heater section has a Curie temperature (To)
less than a phase transformation
temperature, wherein the To is at least 800 C; and wherein the heater section
is configured to provide, when time
varying current is applied, an electrical resistance.
In certain embodiments, the invention provides a method of heating a formation
containing hydrocarbons,
comprising: providing a temperature limited heater to a formation, wherein the
heater comprises a metal section
comprising iron, cobalt, and carbon, wherein the heater section has a Curie
temperature (To) less than a phase
transformation temperature, wherein the T, is at least 800 C; and providing
current to the temperature limited heater
such that the temperature limited heater provides electrical resistance
heating to at least a portion of the formation.
In certain embodiments, the invention provides a heater comprising a metal
section comprising: iron,
cobalt, chromium and carbon; wherein the heater section has a Curie
temperature (To) less than a phase
transformation temperature, wherein the To is at least 740 C; and wherein the
heater section is configured to
provide, when time varying current is applied, an electrical resistance.
In certain embodiments, the invention provides a method of heating a formation
containing hydrocarbons,
comprising: providing a temperature limited heater to a formation, wherein the
heater comprises a metal section
11
CA 02871784 2014-11-18
comprising iron, cobalt, chromium and carbon, wherein the heater section has a
Curie temperature (Tc) less than a
phase transformation temperature, wherein the T is at least 740 C; and
providing current to the temperature limited
heater such that the temperature limited heater provides electrical resistance
heating to at least a portion of the
formation.
In certain embodiments, the invention provides a heater comprising: a metal
section having at least 50% by
weight iron, at least 6% by weight cobalt, at least 9% by weight chromium, and
at least 0.5% by weight vanadium;
wherein the heater section has a Curie temperature ("Fe) less than a phase
transformation temperature, wherein the Tc
is at least 740 C; and wherein the heater section is configured to provide,
when time varying current is applied, an
electrical resistance.
In certain embodiments, the invention provides a method of heating a formation
containing hydrocarbons,
comprising: providing a temperature limited heater to a formation, wherein the
heater comprises a metal section
having at least 50% by weight iron, at least 6% by weight cobalt, at least 9%
by weight chromium, and at least 0.5%
by weight vanadium; wherein the heater section has a Curie temperature (Tc)
less than a phase transformation
temperature, wherein the Tc is at least 740 C; and providing current to the
temperature limited heater such that the
temperature limited heater provides electrical resistance heating to at least
a portion of the formation.
In certain embodiments, the invention provides a heater comprising: a metal
section having at least 50% by
weight iron, at least 9% by weight chromium and at least 0.1% by weight
carbon; wherein the heater section has a
Curie temperature (Tc) less than a phase transformation temperature, wherein
the T, is at least 800 C; and wherein
the heater section is configured to provide, when time varying current is
applied, an electrical resistance.
In certain embodiments, the invention provides a method of heating a formation
containing hydrocarbons,
comprising: providing a temperature limited heater to a formation, wherein the
heater comprises a metal section
having at least 50% by weight iron, at least 9% by weight chromium and at
least 0.1% by weight carbon. wherein the
heater section has a Curie temperature (To) less than a phase transformation
temperature, wherein the Tc is at least
800 C; and providing current to the temperature limited heater such that the
temperature limited heater provides
electrical resistance heating to at least a portion of the formation.
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CA 02871784 2014-11-18
In certain embodiments, the invention provides a method of providing at least
a partial barrier for a
subsurface formation, comprising: providing an opening in the formation;
providing liquefied wax to the opening,
the wax having a solidification temperature that is greater than the
temperature of the portion of the formation in
which the barrier to desired to be formed; pressurizing the liquefied wax such
that at least a portion of the liquefied
wax flows into the formation; and allowing the wax to solidify to form at
least a partial barrier in the formation.
In certain embodiments, the invention provides a method of providing at least
a partial barrier for a
subsurface formation, comprising: providing an opening in the formation;
providing a composition including cross-
linkable polymer to the opening, the composition being configured to solidify
after a selected time in the formation;
pressurizing the composition such that at least a portion of the composition
flows into the formation; and allowing
the composition to solidify to form at least a partial barrier in the
formation.
In certain embodiments, the invention provides a method of containing liquid
hydrocarbon contaminants in
a fracture system of a subsurface formation, comprising: raising a temperature
of the formation near at least one
injection well adjacent to a portion of the formation that contains the liquid
hydrocarbon contaminants above a
melting temperature of a material including wax; introducing molten material
into the formation through at the
injection well, wherein the molten material enters the fracture system and
mixes with the contaminants in the
fracture system; and allowing the molten material to cool in the formation and
congeal to form a containment barrier.
In certain embodiments, the invention provides a method of forming a wellbore
in a formation through at
least two permeable zones, comprising: drilling a first portion of the
wellbore to a depth between a first permeable
zone and a second permeable zone; heating a portion of the wellbore adjacent
to the first permeable zone;
introducing a wax into the wellbore, wherein a portion of the wax enters the
first permeable zone and congeals in the
first permeable zone to form a barrier; and drilling a second portion of the
wellbore through a second permeable
zone to a desired depth.
In certain embodiments, the invention provides a method for heating a
subsurface treatment area,
comprising: producing hot fluid from at least one subsurface layer; and
transferring heat from at least a portion of
the hot fluid to the treatment area.
In certain embodiments, the invention provides a method for heating at least a
portion of a subsurface
treatment area, comprising: introducing a fluid into a hot subsurface layer to
transfer heat from the hot layer to the
fluid; producing at least a portion of the fluid introduced into the hot
layer, wherein the produced fluid is hot fluid at
a temperature higher than the temperature of the fluid introduced into the hot
layer; and transferring heat from at
least a portion of the hot fluid to the treatment area.
In certain embodiments, the invention provides a method of treating a
subsurface treatment area in a
formation, comprising: heating a treatment area to mobilize formation fluid in
the treatment area; and introducing a
fluid into the formation to inhibit migration of formation fluid from the
treatment area.
In certain embodiments, the invention provides a method for treating a
subsurface treatment area in a
formation, comprising: heating a subsurface treatment area with a plurality of
heat sources; and introducing a fluid
into the formation from a plurality of wells offset from the heat sources to
inhibit outward migration of formation
fluid from the treatment area.
In certain embodiments, the invention provides an in situ heat treatment
system for producing hydrocarbons
from a subsurface formation, comprising: a plurality of wellbores in the
formation; piping positioned in at least two
of the wellbores; a fluid circulation system coupled to the piping; and a
nuclear reactor configured to heat a heat
transfer fluid circulated by the circulation system through the piping to heat
the temperature of the formation to
temperatures that allow for hydrocarbon production from the formation.
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CA 02871784 2014-11-18
In certain embodiments, the invention provides a method of heating a
subsurface formation, comprising:
heating a heat transfer fluid using heat exchange with helium heated by a
nuclear reactor; circulating the heat transfer
fluid through piping in the formation to heat a portion of the formation to
allow hydrocarbons to be produced from
the formation; and producing hydrocarbons from the formation.
In certain embodiments, the invention provides a gas burner assembly for
heating a subsurface formation,
comprising: an oxidant line; a fuel line positioned in the oxidant line; and a
plurality of oxidizers coupled to the fuel
line, wherein at least one of the oxidizers includes: a mix chamber for mixing
fuel from the fuel line with an
oxidant; an igniter; a nozzle and flame holder; and a heat shield, wherein the
heat shield comprises a plurality of
openings in communication with the oxidant line.
In certain embodiments, the invention provides a gas burner assembly for
heating a subsurface formation,
comprising: an oxidant line; a fuel line positioned in the oxidant line; and a
plurality of oxidizers coupled to the fuel
line, wherein at least one of the oxidizers includes: a mix chamber for mixing
fuel from the fuel line with an
oxidant; an catalyst chamber configured to produce hot reaction products to
ignite fuel and oxidant; a nozzle and
flame holder; and a heat shield, wherein the heat shield comprises a plurality
of openings in communication with the
oxidant line.
In certain embodiments, the invention provides a gas burner assembly for
heating a subsurface formation,
comprising: an oxidant line; a fuel line positioned in the oxidant line; and a
plurality of oxidizers coupled to the fuel
line, wherein at least one of the oxidizers includes: a mix chamber for mixing
fuel from the fuel line with an
oxidant; an igniter in the mix chamber configured to ignite fuel and oxidant
to preheat fuel and oxidant; an catalyst
chamber configured to react preheated fuel and oxidant from the mix chamber to
produce hot reaction products to
ignite fuel and oxidant; a nozzle and flame holder; and a heat shield, wherein
the heat shield comprises a plurality of
openings in communication with the oxidant line.
In further embodiments, features from specific embodiments may be combined
with features from other
embodiments. For example, features from one embodiment may be combined with
features from any of the other
embodiments.
In further embodiments, treating a subsurface formation is performed using any
of the methods, systems, or
heaters described herein.
= In further embodiments, additional features may be added to the specific
embodiments described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
Advantages of the present invention may become apparent to those skilled in
the art with the benefit of the
following detailed description and upon reference to the accompanying drawings
in which:
FIG. 1 depicts an illustration of stages of heating a hydrocarbon containing
formation.
FIG. 2 shows a schematic view of an embodiment of a portion of an in situ heat
treatment system for
treating a hydrocarbon containing formation.
FIG. 3 depicts a schematic of an embodiment of a Kalina cycle for producing
electricity.
FIG. 4 depicts a schematic of an embodiment of a Kalina cycle for producing
electricity.
FIG. 5 depicts a schematic representation of an embodiment of a system for
producing pipeline gas.
FIG. 6 depicts a schematic representation of an embodiment of a system for
producing pipeline gas.
FIG. 7 depicts a schematic representation of an embodiment of a system for
producing pipeline gas.
FIG. 8 depicts a schematic representation of an embodiment of a system for
producing pipeline gas.
FIG. 9 depicts a schematic representation of an embodiment of a system for
producing pipeline gas.
14
CA 02871784 2014-11-18
FIG. 10 depicts a schematic representation of an embodiment of a system for
treating the mixture produced
from the in situ heat treatment process.
FIG. 11 depicts a schematic representation of an embodiment of a system for
treating a liquid stream
produced from an in situ heat treatment process.
FIG. 12 depicts a schematic drawing of an embodiment of a reverse-circulating
polycrystalline diamond
compact drill bit design.
FIG. 13 depicts a schematic drawing of an embodiment of a drilling system.
FIG. 14 depicts a schematic drawing of an embodiment of a drilling system for
drilling into a hot formation.
FIG. 15 depicts a schematic drawing of an embodiment of a drilling system for
drilling into a hot formation.
FIG. 16 depicts a schematic drawing of an embodiment of a drilling system for
drilling into a hot formation.
FIG. 17 depicts an embodiment of a freeze well for a circulated liquid
refrigeration system, wherein a
cutaway view of the freeze well is represented below ground surface.
FIG. I8A depicts an embodiment of a wellbore for introducing wax into a
formation to form a wax grout
barrier.
FIG. 18B depicts a representation of a wellbore drilled to an intermediate
depth in a formation.
FIG. 18C depicts a representation of the wellbore drilled to the final depth
in the formation.
FIG. 19 depicts an embodiment of a ball type reflux baffle system positioned
in a heater well.
FIG. 20 depicts an embodiment of a device for longitudinal welding of a
tubular using ERW.
FIGS. 21, 22, and 23 depict cross-sectional representations of an embodiment
of a temperature limited
heater with an outer conductor having a ferromagnetic section and a non-
ferromagnetic section.
FIGS. 24, 25, 26, and 27 depict cross-sectional representations of an
embodiment of a temperature limited
heater with an outer conductor having a ferromagnetic section and a non-
ferromagnetic section placed inside a
sheath.
FIGS. 28A and 28B depict cross-sectional representations of an embodiment of a
temperature limited
heater.
FIGS. 29A and 29B depict cross-sectional representations of an embodiment of a
temperature limited
heater.
FIGS. 30A and 30B depict cross-sectional representations of an embodiment of a
temperature limited
heater.
FIGS. 31A and 31B depict cross-sectional representations of an embodiment of a
temperature limited
heater.
FIGS. 32A and 32B depict cross-sectional representations of an embodiment of a
temperature limited
heater.
FIG. 33 depicts a cross-sectional representation of an embodiment of a
composite conductor with a support
member.
FIG. 34 depicts a cross-sectional representation of an embodiment of a
composite conductor with a support
member separating the conductors.
FIG. 35 depicts a cross-sectional representation of an embodiment of a
composite conductor surrounding a
support member.
FIG. 36 depicts a cross-sectional representation of an embodiment of a
composite conductor surrounding a
conduit support member.
FIG. 37 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit heat source.
CA 02871784 2014-11-18
FIG. 38 depicts a cross-sectional representation of an embodiment of a
removable conductor-in-conduit
heat source.
FIG. 39 depicts an embodiment of a temperature limited heater in which the
support member provides a
majority of the heat output below the Curie temperature of the ferromagnetic
conductor.
FIGS. 40 and 41 depict embodiments of temperature limited heaters in which the
jacket provides a majority
of the heat output below the Curie temperature of the ferromagnetic conductor.
FIG. 42 depicts a high temperature embodiment of a temperature limited heater.
FIG. 43 depicts hanging stress versus outside diameter for the temperature
limited heater shown in FIG. 39
with 347H as the support member.
FIG. 44 depicts hanging stress versus temperature for several materials and
varying outside diameters of the
temperature limited heater.
FIGS. 45, 46, 47, and 48 depict examples of embodiments for temperature
limited heaters that vary the
materials and/or dimensions along the length of the heaters to provide desired
operating properties.
FIGS. 49 and 50 depict examples of embodiments for temperature limited heaters
that vary the diameter
and/or materials of the support member along the length of the heaters to
provide desired operating properties and
sufficient mechanical properties.
FIGS. 51A and 51B depict cross-sectional representations of an embodiment of a
temperature limited heater
component used in an insulated conductor heater.
FIGS. 52A and 52B depict an embodiment of a system for installing heaters in a
wellbore.
FIG. 52C depicts an embodiment of an insulated conductor with the sheath
shorted to the conductors.
FIG. 53 depicts an embodiment for coupling together sections of a long
temperature limited heater.
FIG. 54 depicts an embodiment of a shield for orbital welding sections of a
long temperature limited heater.
FIG. 55 depicts a schematic representation of an embodiment of a shut off
circuit for an orbital welding
machine.
FIG. 56 depicts an embodiment of a temperature limited heater with a low
temperature ferromagnetic outer
conductor.
FIG. 57 depicts an embodiment of a temperature limited conductor-in-conduit
heater.
FIG. 58 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater.
FIG. 59 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater.
FIG. 60 depicts a cross-sectional view of an embodiment of a conductor-in-
conduit temperature limited
heater.
FIG. 61 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater with an insulated conductor.
FIG. 62 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater with an insulated conductor.
FIG. 63 depicts an embodiment of a three-phase temperature limited heater with
a portion shown in cross
section.
FIG. 64 depicts an embodiment of temperature limited heaters coupled together
in a three-phase
configuration.
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CA 02871784 2014-11-18
FIG. 65 depicts an embodiment of three heaters coupled in a three-phase
configuration.
FIG. 66 depicts a side view representation of an embodiment of a substantially
u-shaped three-phase heater.
FIG. 67 depicts a top view representation of an embodiment of a plurality of
triads of three-phase heaters in
a formation.
FIG. 68 depicts a top view representation of the embodiment depicted in FIG.
67 with production wells.
FIG. 69 depicts a top view representation of an embodiment of a plurality of
triads of three-phase heaters in
a hexagonal pattern.
FIG. 70 depicts a top view representation of an embodiment of a hexagon from
FIG. 69.
FIG. 71 depicts an embodiment of triads of heaters coupled to a horizontal bus
bar.
FIGS. 72 and 73 depict embodiments for coupling contacting elements of three
legs of a heater.
FIG. 74 depicts an embodiment of a container with an initiator for melting the
coupling material.
FIG. 75 depicts an embodiment of a container for coupling contacting elements
with bulbs on the
contacting elements.
FIG. 76 depicts an alternative embodiment of a container.
FIG. 77 depicts an alternative embodiment for coupling contacting elements of
three legs of a heater.
FIG. 78 depicts a side-view representation of an embodiment for coupling
contacting elements using
temperature limited heating elements.
FIG. 79 depicts a side view representation of an alternative embodiment for
coupling contacting elements
using temperature limited heating elements.
FIG. 80 depicts a side view representation of another alternative embodiment
for coupling contacting
elements using temperature limited heating elements.
FIG. 81 depicts a side view representation of an alternative embodiment for
coupling contacting elements of
three legs of a heater.
FIG. 82 depicts a top view representation of the alternative embodiment for
coupling contacting elements of
three legs of a heater depicted in FIG. 81.
FIG. 83 depicts an embodiment of a contacting element with a brush contactor.
FIG. 84 depicts an embodiment for coupling contacting elements with brush
contactors.
FIG. 85 depicts an embodiment of two temperature limited heaters coupled
together in a single contacting
section.
FIG. 86 depicts an embodiment of two temperature limited heaters with legs
coupled in a contacting
section.
FIG. 87 depicts an embodiment of three diads coupled to a three-phase
transformer.
FIG. 88 depicts an embodiment of groups of diads in a hexagonal pattern.
FIG. 89 depicts an embodiment of diads in a triangular pattern.
FIG. 90 depicts a side-view representation of an embodiment of substantially u-
shaped heaters.
FIG. 91 depicts a representational top view of an embodiment of a surface
pattern of heaters depicted in
FIG. 90.
FIG. 92 depicts a cross-sectional representation of substantially u-shaped
heaters in a hydrocarbon layer.
FIG. 93 depicts a side view representation of an embodiment of substantially
vertical heaters coupled to a
substantially horizontal wellbore.
FIG. 94 depicts an embodiment of a substantially u-shaped heater that
electrically isolates itself from the
formation.
17
CA 02871784 2014-11-18
FIG. 95 depicts an embodiment of a single-ended, substantially horizontal
heater that electrically isolates
itself from the formation.
FIG. 96 depicts an embodiment of a single-ended, substantially horizontal
heater that electrically isolates
itself from the formation using an insulated conductor as the center
conductor.
FIGS. 97A and 97B depict an embodiment for using substantially u-shaped
wellbores to time sequence heat
two layers in a hydrocarbon containing formation.
FIG. 98 depicts a side view representation of an embodiment for producing
mobilized fluids from a tar
sands formation with a relatively thin hydrocarbon layer.
FIG. 99 depicts a side view representation of an embodiment for producing
mobilized fluids from a tar
sands formation with a hydrocarbon layer that is thicker than the hydrocarbon
layer depicted in FIG. 98.
FIG. 100 depicts a side view representation of an embodiment for producing
mobilized fluids from a tar
sands formation with a hydrocarbon layer that is thicker than the hydrocarbon
layer depicted in FIG. 99.
FIG. 101 depicts a side view representation of an embodiment for producing
mobilized fluids from a tar
sands formation with a hydrocarbon layer that has a shale break.
FIG. 102 depicts a top view representation of an embodiment for preheating
using heaters for the drive
process.
FIG. 103 depicts a side view representation of an embodiment for preheating
using heaters for the drive
process.
FIG. 104 depicts a representation of an embodiment for producing hydrocarbons
from a tar sands
formation.
FIG. 105 depicts an embodiment for heating and producing from a formation with
a temperature limited
heater in a production wellbore.
FIG. 106 depicts an embodiment for heating and producing from a formation with
a temperature limited
heater and a production wellbore.
FIG. 107 depicts an embodiment of a heating/production assembly that may be
located in a wellbore for gas
lifting.
FIG. 108 depicts an embodiment of a heating/production assembly that may be
located in a wellbore for gas
lifting.
FIG. 109 depicts another embodiment of a heating/production assembly that may
be located in a wellbore
for gas lifting.
FIG. 110 depicts an embodiment of a production conduit and a heater.
FIG. III depicts an embodiment for treating a formation.
FIG. 112 depicts an embodiment of a heater well with selective heating.
FIG. 113 depicts a schematic representation of an embodiment of a downhole
oxidizer assembly.
FIG. 114 depicts an embodiment of a portion of an oxidizer of an oxidation
system.
FIG. 115 depicts a schematic representation of an oxidizer positioned in an
oxidant line.
FIG. 116 depicts a cross-sectional view of an embodiment of a heat shield.
FIG. 117 depicts a cross-sectional view of an embodiment of a heat shield.
FIG. 118 depicts a cross-sectional view of an embodiment of a heat shield.
FIG. 119 depicts a cross-sectional view of an embodiment of a heat shield.
FIG. 120 depicts a cross-sectional view of an embodiment of a heat shield.
FIG. 121 depicts a cross-sectional representation of an embodiment of a
catalytic burner.
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FIG. 122 depicts a cross-sectional representation of an embodiment of a
catalytic burner with an igniter.
FIG. 123 depicts a schematic representation of an embodiment of a heating
system with a downhole gas
turbine.
FIG. 124 depicts a schematic representation of a closed loop circulation
system for heating a portion of a
formation.
FIG. 125 depicts a plan view of wellbore entries and exits from a portion of a
formation to be heated using a
closed loop circulation system.
FIG. 126 depicts a schematic representation of an embodiment of an in situ
heat treatment system that uses
a nuclear reactor.
FIG. 127 depicts an elevational view of an in situ heat treatment system using
pebble bed reactors.
FIG. 128 depicts a side view representation of an embodiment of a system for
heating the formation that
can use a closed loop circulation system and/or electrical heating.
FIG. 129 depicts a side view representation of an embodiment for an in situ
staged heating and producing
process for treating a tar sands formation.
FIG. 130 depicts a top view of a rectangular checkerboard pattern embodiment
for the in situ staged heating
and production process.
FIG. 131 depicts a top view of a ring pattern embodiment for the in situ
staged heating and production
process.
FIG. 132 depicts a top view of a checkerboard ring pattern embodiment for the
in situ staged heating and
production process.
FIG. 133 depicts a top view an embodiment of a plurality of rectangular
checkerboard patterns in a
treatment area for the in situ staged heating and production process.
FIG. 134 depicts a schematic representation of a system for inhibiting
migration of formation fluid from a
treatment area.
FIG. 135 depicts an embodiment of a windmill for generating electricity for
subsurface heaters.
FIG. 136 depicts an embodiment of a solution mining well.
FIG. 137 depicts a representation of a portion of a solution mining well.
FIG. 138 depicts a representation of a portion of a solution mining well.
FIG. 139 depicts an elevational view of a well pattern for solution mining
and/or an in situ heat treatment
process.
FIG. 140 depicts a representation of wells of an in situ heating treatment
process for solution mining and
producing hydrocarbons from a formation.
FIG. 141 depicts an embodiment for solution mining a formation.
FIG. 142 depicts an embodiment of a formation with nahcolite layers in the
formation before solution
mining nahcolite from the formation.
FIG. 143 depicts the formation of FIG. 142 after the nahcolite has been
solution mined.
FIG. 144 depicts an embodiment of two injection wells interconnected by a zone
that has been solution
mined to remove nahcolite from the zone.
FIG. 145 depicts an embodiment for heating a formation with dawsonite in the
formation.
FIG. 146 depicts an embodiment of treating a hydrocarbon containing formation
with a combustion front.
FIG. 147 depicts an embodiment of cross-sectional view of treating a
hydrocarbon containing formation
with a combustion front.
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CA 02871784 2014-11-18
FIG. 148 depicts electrical resistance versus temperature at various applied
electrical currents for a 446
stainless steel rod.
FIG. 149 shows resistance profiles as a function of temperature at various
applied electrical currents for a
copper rod contained in a conduit of Sumitomo HCM12A.
FIG. 150 depicts electrical resistance versus temperature at various applied
electrical currents for a
temperature limited heater.
FIG. 151 depicts raw data fora temperature limited heater.
FIG. 152 depicts electrical resistance versus temperature at various applied
electrical currents for a
temperature limited heater.
FIG. 153 depicts power versus temperature at various applied electrical
currents for a temperature limited
heater.
FIG. 154 depicts electrical resistance versus temperature at various applied
electrical currents for a
temperature limited heater.
FIG. 155 depicts data of electrical resistance versus temperature for a solid
2.54 cm diameter, 1.8 m long
410 stainless steel rod at various applied electrical currents.
FIG. 156 depicts data of electrical resistance versus temperature for a
composite 1.9 cm, 1.8 m long alloy
42-6 rod with a copper core (the rod has an outside diameter to copper
diameter ratio of 2:1) at various applied
electrical currents.
FIG. 157 depicts data of power output versus temperature for a composite 1.9
cm, 1.8 m long alloy 42-6 rod
with a copper core (the rod has an outside diameter to copper diameter ratio
of 2:1) at various applied electrical
currents.
FIG. 158 depicts data for values of skin depth versus temperature for a solid
2.54 cm diameter, 1.8 m long
410 stainless steel rod at various applied AC electrical currents.
FIG. 159 depicts temperature versus time for a temperature limited heater.
FIG. 160 depicts temperature versus log time data for a 2.5 cm solid 410
stainless steel rod and a 2.5 cm
solid 304 stainless steel rod.
FIG. 161 depicts experimentally measured resistance versus temperature at
several currents for a
temperature limited heater with a copper core, a carbon steel ferromagnetic
conductor, and a stainless steel 347H
stainless steel support member.
FIG. 162 depicts experimentally measured resistance versus temperature at
several currents for a
temperature limited heater with a copper core, an iron-cobalt ferromagnetic
conductor, and a stainless steel 347H
stainless steel support member.
FIG. 163 depicts experimentally measured power factor versus temperature at
two AC currents for a
temperature limited heater with a copper core, a carbon steel ferromagnetic
conductor, and a 347H stainless steel
support member.
FIG. 164 depicts experimentally measured turndown ratio versus maximum power
delivered for a
temperature limited heater with a copper core, a carbon steel ferromagnetic
conductor, and a 347H stainless steel
support member.
FIG. 165 depicts examples of relative magnetic permeability versus magnetic
field for both the found
correlations and raw data for carbon steel.
FIG. 166 shows the resulting plots of skin depth versus magnetic field for
four temperatures and 400 A
current.
CA 02871784 2014-11-18
FIG. 167 shows a comparison between the experimental and numerical
(calculated) results for currents of
300 A, 400 A, and 500 A.
FIG. 168 shows the AC resistance per foot of the heater element as a function
of skin depth at 1100 F
calculated from the theoretical model.
FIG. 169 depicts the power generated per unit length in each heater component
versus skin depth for a
temperature limited heater.
FIGS. 170 A-C compare the results of theoretical calculations with
experimental data for resistance versus
temperature in a temperature limited heater.
FIG. 171 displays temperature of the center conductor of a conductor-in-
conduit heater as a function of
formation depth for a Curie temperature heater with a turndown ratio of 2:1.
FIG. 172 displays heater heat flux through a formation for a turndown ratio of
2:1 along with the oil shale
richness profile.
FIG. 173 displays heater temperature as a function of formation depth for a
turndown ratio of 3:1.
FIG. 174 displays heater heat flux through a formation for a turndown ratio of
3:1 along with the oil shale
richness profile.
FIG. 175 displays heater temperature as a function of formation depth for a
turndown ratio of 4:1.
FIG. 176 depicts heater temperature versus depth for heaters used in a
simulation for heating oil shale.
FIG. 177 depicts heater heat flux versus time for heaters used in a simulation
for heating oil shale.
FIG. 178 depicts accumulated heat input versus time in a simulation for
heating oil shale.
FIG. 179 depicts cumulative gas production and cumulative oil production
versus time found from a
STARS simulation using the heaters and heater pattern depicted in FIGS. 65 and
67.
FIG. 180 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for iron alloy TC3.
FIG. 181 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for iron alloy FM-4.
FIG. 182 depicts the Curie temperature and phase transformation temperature
range for several iron alloys.
FIG. 183 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-cobalt alloy with 5.63% by weight cobalt and 0.4% by
weight manganese.
FIG. 184 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by
weight manganese, and 0.01% carbon.
FIG. 185 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by
weight manganese, and 0.085% carbon.
FIG. 186 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by
weight manganese, 0.085% carbon, and
0.4% titanium.
FIG. 187 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-chromium alloys having 12.25% by weight chromium, 0.1%
by weight carbon, 0.5% by
weight manganese, and 0.5% by weight silicon.
FIG. 188 depicts experimental calculation of weight percentages of phases
versus weight percentages of
chromium in an alloy.
FIG. 189 depicts experimental calculation of weight percentages of phases
versus weight percentages of
silicon in an alloy.
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FIG. 190 depicts experimental calculation of weight percentages of phases
versus weight percentages of
tungsten in an alloy.
FIG. 191 depicts experimental calculation of weight percentages of phases
versus weight percentages of
niobium in an alloy.
FIG. 192 depicts experimental calculation of weight percentages of phases
versus weight percentages of
carbon in an alloy.
FIG. 193 depicts experimental calculation of weight percentages of phases
versus weight percentages of
nitrogen in an alloy.
FIG. 194 depicts experimental calculation of weight percentages of phases
versus weight percentages of
titanium in an alloy.
FIG. 195 depicts experimental calculation of weight percentages of phases
versus weight percentages of
copper in an alloy.
FIG. 196 depicts experimental calculation of weight percentages of phases
versus weight percentages of
manganese in an alloy.
FIG. 197 depicts experimental calculation of weight percentages of phases
versus weight percentages of
= nickel in an alloy.
FIG. 198 depicts experimental calculation of weight percentages of phases
versus weight percentages of
molybdenum in an alloy.
FIG. 199 depicts yield strengths and ultimate tensile strengths for different
metals.
FIG. 200 depicts projected corrosion rates over a one-year period for several
metals in a sulfidation
atmosphere.
FIG. 201 depicts projected corrosion rates over a one-year period for 410
stainless steel and 410 stainless
steel containing various amounts of cobalt in a sulfidation atmosphere.
FIG. 202 depicts an example of richness of an oil shale formation (gal/ton)
versus depth (ft).
FIG. 203 depicts resistance per foot (m0/ft) versus temperature ( F) profile
of the first heater example.
FIG. 204 depicts average temperature in the formation ( F) versus time (days)
as determined by the
simulation for the first example.
FIG. 205 depicts resistance per foot (mil/ft) versus temperature ( F) for the
second heater example.
FIG. 206 depicts average temperature in the formation ( F) versus time (days)
as determined by the
simulation for the second example.
FIG. 207 depicts net heater energy input (Btu) versus time (days) for the
second example.
FIG. 208 depicts power injection per foot (W/ft) versus time (days) for the
second example.
FIG. 209 depicts resistance per foot (mC2/ft) versus temperature ( F) for the
third heater example.
FIG. 210 depicts average temperature in the formation ( F) versus time (days)
as determined by the
simulation for the third example.
FIG. 211 depicts cumulative energy injection (Btu) versus time (days) for each
of the three heater examples.
FIG. 212 depicts average temperature ( F) versus time (days) for the third
heater example with a 30 foot
spacing between heaters in the formation as determined by the simulation.
FIG. 213 depicts average temperature ( F) versus time (days) for the fourth
heater example using the heater
configuration and pattern depicted in FIGS. 65 and 67 as determined by the
simulation.
FIG. 214 depicts a temperature profile in the formation after 360 days using
the STARS simulation.
FIG. 215 depicts an oil saturation profile in the formation after 360 days
using the STARS simulation.
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FIG. 216 depicts the oil saturation profile in the formation after 1095 days
using the STARS simulation.
FIG. 217 depicts the oil saturation profile in the formation after 1470 days
using the STARS simulation.
FIG. 218 depicts the oil saturation profile in the formation after 1826 days
using the STARS simulation.
FIG. 219 depicts the temperature profile in the formation after 1826 days
using the STARS simulation.
FIG. 220 depicts oil production rate and gas production rate versus time.
While the invention is susceptible to various modifications and alternative
forms, specific embodiments
thereof are shown by way of example in the drawings and may herein be
described in detail. The drawings may not
be to scale. It should be understood, however, that the drawings and detailed
description thereto are not intended to
limit the invention to the particular form disclosed, but on the contrary, the
intention is to cover all modifications,
equivalents and alternatives falling within the spirit and scope of the
present invention as defined by the appended
claims.
DETAILED DESCRIPTION
The following description generally relates to systems and methods for
treating hydrocarbons in the
formations. Such formations may be treated to yield hydrocarbon products,
hydrogen, and other products.
"Alternating current (AC)" refers to a time-varying current that reverses
direction substantially sinusoidally.
AC produces skin effect electricity flow in a ferromagnetic conductor.
"API gravity" refers to API gravity at 15.5 C (60 F). API gravity is as
determined by ASTM Method
D6822.
In the context of reduced heat output heating systems, apparatus, and methods,
the term "automatically"
means such systems, apparatus, and methods function in a certain way without
the use of external control (for
example, external controllers such as a controller with a temperature sensor
and a feedback loop, PID controller, or
predictive controller).
"Bare metal" and "exposed metal" refer to metals of elongated members that do
not include a layer of
electrical insulation, such as mineral insulation, that is designed to provide
electrical insulation for the metal
throughout an operating temperature range of the elongated member. Bare metal
and exposed metal may encompass
a metal that includes a corrosion inhibiter such as a naturally occurring
oxidation layer, an applied oxidation layer,
and/or a film. Bare metal and exposed metal include metals with polymeric or
other types of electrical insulation
that cannot retain electrical insulating properties at typical operating
temperature of the elongated member. Such
material may be placed on the metal and may be thermally degraded during use
of the heater.
"Carbon number" refers to the number of carbon atoms in a molecule. A
hydrocarbon fluid may include
various hydrocarbons with different carbon numbers. The hydrocarbon fluid may
be described by a carbon number
distribution. Carbon numbers and/or carbon number distributions may be
determined by true boiling point
distribution and/or gas-liquid chromatography.
"Cenospheres" refers to hollow particulate that are formed in thermal
processes at high temperatures when
molten components are blown up like balloons by the volatilization of organic
components.
"Chemically stability" refers to the ability of a formation fluid to be
transported without components in the
formation fluid reacting to form polymers and/or compositions that plug
pipelines, valves, and/or vessels.
"Clogging" refers to impeding and/or inhibiting flow of one or more
compositions through a process vessel
or a conduit.
23
CA 02871784 2014-11-18
"Column X element" or "Column X elements" refer to one or more elements of
Column X of the Periodic
Table, and/or one or more compounds of one or more elements of Column X of the
Periodic Table, in which X
corresponds to a column number (for example, 13-18) of the Periodic Table. For
example, "Column 15 elements"
refer to elements from Column 15 of the Periodic Table and/or compounds of one
or more elements from Column 15
of the Periodic Table.
"Column X metal" or "Column X metals" refer to one or more metals of Column X
of the Periodic Table
and/or one or more compounds of one or more metals of Column X of the Periodic
Table, in which X corresponds to
a column number (for example, 1-12) of the Periodic Table. For example,
"Column 6 metals" refer to metals from
Column 6 of the Periodic Table and/or compounds of one or more metals from
Column 6 of the Periodic Table.
"Condensable hydrocarbons" are hydrocarbons that condense at 25 C and one
atmosphere absolute
pressure. Condensable hydrocarbons may include a mixture of hydrocarbons
having carbon numbers greater than 4.
"Non-condensable hydrocarbons" are hydrocarbons that do not condense at 25 C
and one atmosphere absolute
pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon
numbers less than 5.
"Coring" is a process that generally includes drilling a hole into a formation
and removing a substantially
solid mass of the formation from the hole.
"Cracking" refers to a process involving decomposition and molecular
recombination of organic
compounds to produce a greater number of molecules than were initially
present. In cracking, a series of reactions
take place accompanied by a transfer of hydrogen atoms between molecules. For
example, naphtha may undergo a
thermal cracking reaction to form ethene and H2.
"Curie temperature" is the temperature above which a ferromagnetic material
loses all of its ferromagnetic
properties. In addition to losing all of its ferromagnetic properties above
the Curie temperature, the ferromagnetic
material begins to lose its ferromagnetic properties when an increasing
electrical current is passed through the
ferromagnetic material.
"Cycle oil" refers to a mixture of light cycle oil and heavy cycle oil. "Light
cycle oil" refers to
hydrocarbons having a boiling range distribution between 430 F (221 C) and
650 F (343 C) that are produced
from a fluidized catalytic cracking system. Light cycle oil content is
determined by ASTM Method D5307. "Heavy
cycle oil" refers to hydrocarbons having a boiling range distribution between
650 F (343 C) and 800 F (427 C)
that are produced from a fluidized catalytic cracking system. Heavy cycle oil
content is determined by ASTM
Method D5307.
"Diad" refers to a group of two items (for example, heaters, wellbores, or
other objects) coupled together.
"Diesel" refers to hydrocarbons with a boiling range distribution between 260
C and 343 C (500-650 F)
at 0.101 MPa. Diesel content is determined by ASTM Method D2887.
"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.
"Fluid pressure" is a pressure generated by a fluid in a formation.
"Lithostatic pressure" (sometimes
referred to as "lithostatic stress") is a pressure in a formation equal to a
weight per unit area of an overlying rock
mass. "Hydrostatic pressure" is a pressure in a formation exerted by a column
of water.
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
impermeable materials. For example,
the overburden and/or underburden may include rock, shale, mudstone, or
wet/tight carbonate. In some
24
CA 02871784 2014-11-18
embodiments of in situ heat treatment processes, the overburden and/or the
underburden may include a hydrocarbon
containing layer or hydrocarbon containing layers that are relatively
impermeable and are not subjected to
temperatures during in situ heat treatment processing that result in
significant characteristic changes of the
hydrocarbon containing layers of the overburden and/or the underburden. For
example, the underburden may
contain shale or mudstone, but the underburden is not allowed to heat to
pyrolysis temperatures during the in situ
heat treatment process. In some cases, the overburden and/or the underburden
may be somewhat permeable.
"Formation fluids" refer to fluids present in a formation and may include
pyrolyzation fluid, synthesis gas,
mobilized hydrocarbon, 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 thermal treatment of the formation. "Produced fluids"
refer to fluids removed from the
formation.
"Gasoline hydrocarbons" refer to hydrocarbons having a boiling point range
from 32 C (90 F) to about
204 C (400 F). Gasoline hydrocarbons include, but are not limited to,
straight run gasoline, naphtha, fluidized or
thermally catalytically cracked gasoline, VB gasoline, and coker gasoline.
Gasoline hydrocarbons content is
determined by ASTM Method D2887.
A "heat source" is any system for providing heat to at least a portion of a
formation substantially by
conductive and/or radiative heat transfer. For example, a heat source may
include electric heaters such as an
insulated conductor, an elongated member, and/or a conductor disposed in a
conduit. A heat source may also
include systems that generate heat by burning a fuel external to or in a
formation. The systems may be surface
burners, downhole gas burners, flameless distributed combustors, and natural
distributed combustors. In some
embodiments, heat provided to or generated in one or more heat sources may be
supplied by other sources of energy.
The other sources of energy may directly heat a formation, or the energy may
be applied to a transfer medium that
directly or indirectly heats the formation. It is to be understood that one or
more heat sources that are applying heat
to a formation may use different sources of energy. Thus, for example, for a
given formation some heat sources may
supply heat from electric resistance heaters, some heat sources may provide
heat from combustion, and some heat
sources may provide heat from one or more other energy sources (for example,
chemical reactions, solar energy,
wind energy, biomass, or other sources of renewable energy). A chemical
reaction may include an exothermic
reaction (for example, an oxidation reaction). A heat source may also include
a heater that provides heat to a zone
proximate and/or surrounding a heating location such as a heater well.
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, ancUor combinations thereof
"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 sulfur, oxygen, and nitrogen. Additional
elements may also be present in heavy
hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API
gravity. Heavy hydrocarbons
generally have an API gravity below about 20 . Heavy oil, for example,
generally has an API gravity of about 10-
20 , whereas tar generally has an API gravity below about 10 . The viscosity
of heavy hydrocarbons is generally
greater than about 100 centipoise at 15 C. Heavy hydrocarbons may include
aromatics or other complex ring
hydrocarbons.
Heavy hydrocarbons may be found in a relatively permeable formation. The
relatively permeable formation
may include heavy hydrocarbons entrained in, for example, sand or carbonate.
"Relatively permeable" is defined,
CA 02871784 2014-11-18
with respect to formations or portions thereof, as an average permeability of
10 millidarcy or more (for example, 10
or 100 millidarcy). "Relatively low permeability" is defined, with respect to
formations or portions thereof, as an
average permeability of less than about 10 millidarcy. One darcy is equal to
about 0.99 square micrometers. An
impermeable layer generally has a permeability of less than about 0.1
millidarcy.
Certain types of formations that include heavy hydrocarbons may also be, but
are not limited to, natural
mineral waxes, or natural asphaltites. "Natural mineral waxes" typically occur
in substantially tubular veins that
may be several meters wide, several kilometers long, and hundreds of meters
deep. "Natural asphaltites" include
solid hydrocarbons of an aromatic composition and typically occur in large
veins. In situ recovery of hydrocarbons
from formations such as natural mineral waxes and natural asphaltites may
include melting to form liquid
hydrocarbons and/or solution mining of hydrocarbons from the formations.
"Hydrocarbons" are generally defined as molecules formed primarily by carbon
and hydrogen atoms.
Hydrocarbons may also include other elements such as, but not limited to,
halogens, metallic elements, nitrogen,
oxygen, and/or sulfur. 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, water, and ammonia.
An "in situ conversion process" refers to a process of heating a hydrocarbon
containing formation from heat
sources to raise the temperature of at least a portion of the formation above
a pyrolysis temperature so that
pyrolyzation fluid is produced in the formation.
An "in situ heat treatment process" refers to a process of heating a
hydrocarbon containing formation with
heat sources to raise the temperature of at least a portion of the formation
above a temperature that results in
mobilized fluid, visbreaking, and/or pyrolysis of hydrocarbon containing
material so that mobilized fluids, visbroken
fluids, and/or pyrolyzation fluids are produced in the formation.
"Insulated conductor" refers to any elongated material that is able to conduct
electricity and that is covered,
in whole or in part, by an electrically insulating material.
"Karst" is a subsurface shaped by the dissolution of a soluble layer or layers
of bedrock, usually carbonate
rock such as limestone or dolomite. The dissolution may be caused by meteoric
or acidic water. The Grosmont
formation in Alberta, Canada is an example of a karst (or "karsted") carbonate
formation.
"Kerogen" is a solid, insoluble hydrocarbon that has been converted by natural
degradation and that
principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Coal and
oil shale are typical examples of
materials that contain kerogen. "Bitumen" is a non-crystalline solid or
viscous hydrocarbon material that is
substantially soluble in carbon disulfide. "Oil" is a fluid containing a
mixture of condensable hydrocarbons.
"Kerosene" refers to hydrocarbons with a boiling range distribution between
204 C and 260 C at 0.101
MPa. Kerosene content is determined by ASTM Method D2887.
"Modulated direct current (DC)" refers to any substantially non-sinusoidal
time-varying current that
produces skin effect electricity flow in a ferromagnetic conductor.
"Naphtha" refers to hydrocarbon components with a boiling range distribution
between 38 C and 200 C at
0.101 MPa. Naphtha content is determined by American Standard Testing and
Materials (ASTM) Method D5307.
"Nitride" refers to a compound of nitrogen and one or more other elements of
the Periodic Table. Nitrides
include, but are not limited to, silicon nitride, boron nitride, or alumina
nitride.
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"Octane Number" refers to a calculated numerical representation of the
antiknock properties of a motor fuel
compared to a standard reference fuel. A calculated octane number is
determined by ASTM Method D6730.
"Olefins" are molecules that include unsaturated hydrocarbons having one or
more non-aromatic carbon-
carbon double bonds.
"Orifices" refer to openings, such as openings in conduits, having a wide
variety of sizes and cross-
sectional shapes including, but not limited to, circles, ovals, squares,
rectangles, triangles, slits, or other regular or
irregular shapes.
"Periodic Table" refers to the Periodic Table as specified by the
International Union of Pure and Applied
Chemistry (IUPAC), November 2003. In the scope of this application, weight of
a metal from the Periodic Table,
weight of a compound of a metal from the Periodic Table, weight of an element
from the Periodic Table, or weight
of a compound of an element from the Periodic Table is calculated as the
weight of metal or the weight of element.
For example, if 0.1 grams of Mo03 is used per gram of catalyst, the calculated
weight of the molybdenum metal in
the catalyst is 0.067 grams per gram of catalyst.
"Physical stability" refers the ability of a formation fluid to not exhibit
phase separate or flocculation during
transportation of the fluid. Physical stability is determined by ASTM Method
D7060.
"Pyrolysis" is the breaking of chemical bonds due to the application of heat.
For example, pyrolysis may
include transforming a compound into one or more other substances by heat
alone. Heat may be transferred to a
section of the formation to cause pyrolysis.
"Pyrolyzation fluids" or "pyrolysis products" refers to fluid produced
substantially during pyrolysis of
hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids
in a formation. The mixture would
be considered pyrolyzation fluid or pyrolyzation product. As used herein,
"pyrolysis zone" refers to a volume of a
formation (for example, a relatively permeable formation such as a tar sands
formation) that is reacted or reacting to
form a pyrolyzation fluid.
"Rich layers" in a hydrocarbon containing formation are relatively thin layers
(typically about 0.2 m to
about 0.5 m thick). Rich layers generally have a richness of about 0.150 L/kg
or greater. Some rich layers have a
richness of about 0.170 L/kg or greater, of about 0.190 L/kg or greater, or of
about 0.210 L/kg or greater. Lean
layers of the formation have a richness of about 0.100 L/kg or less and are
generally thicker than rich layers. The
richness and locations of layers are determined, for example, by coring and
subsequent Fischer assay of the core,
density or neutron logging, or other logging methods. Rich layers may have a
lower initial thermal conductivity than
other layers of the formation. Typically, rich layers have a thermal
conductivity 1.5 times to 3 times lower than the
thermal conductivity of lean layers. In addition, rich layers have a higher
thermal expansion coefficient than lean
layers of the formation.
"Smart well technology" or "smart wellbore" refers to wells that incorporate
downhole measurement and/or
control. For injection wells, smart well technology may allow for controlled
injection of fluid into the formation in
desired zones. For production wells, smart well technology may allow for
controlled production of formation fluid
from selected zones. Some wells may include smart well technology that allows
for formation fluid production from
selected zones and simultaneous or staggered solution injection into other
zones. Smart well technology may
include fiber optic systems and control valves in the wellbore. A smart
wellbore used for an in situ heat treatment
process may be Westbay Multilevel Well System MP55 available from Westbay
Instruments Inc. (Burnaby, British
Columbia, Canada).
"Subsidence" is a downward movement of a portion of a formation relative to an
initial elevation of the
surface.
27
CA 02871784 2014-11-18
"Superposition of heat" refers to providing heat from two or more heat sources
to a selected section of a
formation such that the temperature of the formation at least at one location
between the heat sources is influenced
by the heat sources.
"Synthesis gas" is a mixture including hydrogen and carbon monoxide.
Additional components of
synthesis gas may include water, carbon dioxide, nitrogen, methane, and other
gases. Synthesis gas may be
generated by a variety of processes and feedstocks. Synthesis gas may be used
for synthesizing a wide range of
compounds.
"Tar" is a viscous hydrocarbon that generally has a viscosity greater than
about 10,000 centipoise at 15 C.
The specific gravity of tar generally is greater than 1.000. Tar may have an
API gravity less than 10 .
A "tar sands formation" is 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.
"Temperature limited heater" generally refers to a heater that regulates heat
output (for example, reduces
heat output) above a specified temperature without the use of external
controls such as temperature controllers,
power regulators, rectifiers, or other devices. Temperature limited heaters
may be AC (alternating current) or
modulated (for example, "chopped") DC (direct current) powered electrical
resistance heaters.
"Thermally conductive fluid" includes fluid that has a higher thermal
conductivity than air at standard
temperature and pressure (STP) (0 C and 101.325 kPa).
"Thermal conductivity" is a property of a material that describes the rate at
which heat flows, in steady
state, between two surfaces of the material for a given temperature difference
between the two surfaces.
"Thermal fracture" refers to fractures created in a formation caused by
expansion or contraction of a
formation and/or fluids in the formation, which is in turn caused by
increasing/decreasing the temperature of the
formation and/or fluids in the formation, and/or by increasing/decreasing a
pressure of fluids in the formation due to
heating.
"Thickness" of a layer refers to the thickness of a cross section of the
layer, wherein the cross section is
normal to a face of the layer.
"Time-varying current" refers to electrical current that produces skin effect
electricity flow in a
ferromagnetic conductor and has a magnitude that varies with time. Time-
varying current includes both alternating
current (AC) and modulated direct current (DC).
"Triad" refers to a group of three items (for example, heaters, wellbores, or
other objects) coupled together.
"Turndown ratio" for the temperature limited heater is the ratio of the
highest AC or modulated DC
resistance below the Curie temperature to the lowest resistance above the
Curie temperature for a given current.
A "u-shaped wellbore" refers to a wellbore that extends from a first opening
in the formation, through at
least a portion of the formation, and out through a second opening in the
formation. In this context, the wellbore
may be only roughly in the shape of a "v" or "u", with the understanding that
the "legs" of the "u" do not need to be
parallel to each other, or perpendicular to the "bottom" of the "u" for the
wellbore to be considered "u-shaped".
"Upgrade" refers to increasing the quality of hydrocarbons. For example,
upgrading heavy hydrocarbons
may result in an increase in the API gravity of the heavy hydrocarbons.
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CA 02871784 2014-11-18
"Visbreaking" refers to the untangling of molecules in fluid during heat
treatment and/or to the breaking of
large molecules into smaller molecules during heat treatment, which results in
a reduction of the viscosity of the
fluid.
"VGO" or "vacuum gas oil" refers to hydrocarbons with a boiling range
distribution between 343 C and
538 C at 0.101 MPa. VG0 content is determined by ASTM Method D5307.
A -vug" is a cavity, void or large pore in a rock that is commonly lined with
mineral precipitates.
"Wax" refers to a low melting organic mixture, or a compound of high molecular
weight that is a solid at
lower temperatures and a liquid at higher temperatures, and when in solid form
can form a barrier to water.
Examples of waxes include animal waxes, vegetable waxes, mineral waxes,
petroleum waxes, and synthetic waxes.
The term "wellbore" refers to a hole in a formation made by drilling or
insertion of a conduit into the
formation. A wellbore may have a substantially circular cross section, or
another cross-sectional shape. As used
herein, the terms "well" and "opening," when referring to an opening in the
formation may be used interchangeably
with the term "wellbore."
Hydrocarbons in formations may be treated in various ways to produce many
different products. In certain
embodiments, hydrocarbons in formations are treated in stages. FIG. 1 depicts
an illustration of stages of heating the
hydrocarbon containing formation. FIG. 1 also depicts an example of yield
("Y") in barrels of oil equivalent per ton
(y axis) of formation fluids from the formation versus temperature ("T") of
the heated formation in degrees Celsius
(x axis).
Desorption of methane and vaporization of water occurs during stage 1 heating.
Heating of the formation
through stage I may be performed as quickly as possible. For example, when the
hydrocarbon containing formation
is initially heated, hydrocarbons in the formation desorb adsorbed methane.
The desorbed methane may be produced
from the formation. If the hydrocarbon containing formation is heated further,
water in the hydrocarbon containing
formation is vaporized. Water may occupy, in some hydrocarbon containing
formations, between 10% and 50% of
the pore volume in the formation. In other formations, water occupies larger
or smaller portions of the pore volume.
Water typically is vaporized in a formation between 160 C and 285 C at
pressures of 600 kPa absolute to 7000 kPa
absolute. In some embodiments, the vaporized water produces wettability
changes in the formation and/or increased
formation pressure. The wettability changes and/or increased pressure may
affect pyrolysis reactions or other
reactions in the formation. In certain embodiments, the vaporized water is
produced from the formation. In other
embodiments, the vaporized water is used for steam extraction and/or
distillation in the formation or outside the
formation. Removing the water from and increasing the pore volume in the
formation increases the storage space for
hydrocarbons in the pore volume.
In certain embodiments, after stage 1 heating, the formation is heated
further, such that a temperature in the
formation reaches (at least) an initial pyrolyzation temperature (such as a
temperature at the lower end of the
temperature range shown as stage 2). Hydrocarbons in the formation may be
pyrolyzed throughout stage 2. A
pyrolysis temperature range varies depending on the types of hydrocarbons in
the formation. The pyrolysis
temperature range may include temperatures between 250 C and 900 C. The
pyrolysis temperature range for
producing desired products may extend through only a portion of the total
pyrolysis temperature range. In some
embodiments, the pyrolysis temperature range for producing desired products
may include temperatures between
250 C and 400 C or temperatures between 270 C and 350 C. If a temperature
of hydrocarbons in the formation
is slowly raised through the temperature range from 250 C to 400 C,
production of pyrolysis products may be
substantially complete when the temperature approaches 400 C. Average
temperature of the hydrocarbons may be
raised at a rate of less than 5 C per day, less than 2 C per day, less than
1 C per day, or less than 0.5 C per day
29
CA 02871784 2014-11-18
through the pyrolysis temperature range for producing desired products.
Heating the hydrocarbon containing
formation with a plurality of heat sources may establish thermal gradients
around the heat sources that slowly raise
the temperature of hydrocarbons in the formation through the pyrolysis
temperature range.
The rate of temperature increase through the pyrolysis temperature range for
desired products may affect
the quality and quantity of the formation fluids produced from the hydrocarbon
containing formation. Raising the
temperature slowly through the pyrolysis temperature range for desired
products may inhibit mobilization of large
chain molecules in the formation. Raising the temperature slowly through the
pyrolysis temperature range for
desired products may limit reactions between mobilized hydrocarbons that
produce undesired products. Slowly
raising the temperature of the formation through the pyrolysis temperature
range for desired products may allow for
the production of high quality, high API gravity hydrocarbons from the
formation. Slowly raising the temperature of
the formation through the pyrolysis temperature range for desired products may
allow for the removal of a large
amount of the hydrocarbons present in the formation as hydrocarbon product.
In some in situ heat treatment embodiments, a portion of the formation is
heated to a desired temperature
instead of slowly heating the temperature through a temperature range. In some
embodiments, the desired
temperature is 300 C, 325 C, or 350 C. Other temperatures may be selected
as the desired temperature.
Superposition of heat from heat sources allows the desired temperature to be
relatively quickly and efficiently
established in the formation. Energy input into the formation from the heat
sources may be adjusted to maintain the
temperature in the formation substantially at the desired temperature. The
heated portion of the formation is
maintained substantially at the desired temperature until pyrolysis declines
such that production of desired formation
fluids from the formation becomes uneconomical. Parts of the formation that
are subjected to pyrolysis may include
regions brought into a pyrolysis temperature range by heat transfer from only
one heat source.
In certain embodiments, formation fluids including pyrolyzation fluids are
produced from the formation.
As the temperature of the formation increases, the amount of condensable
hydrocarbons in the produced formation
fluid may decrease. At high temperatures, the formation may produce mostly
methane and/or hydrogen. If the
hydrocarbon containing formation is heated throughout an entire pyrolysis
range, the formation may produce only
small amounts of hydrogen towards an upper limit of the pyrolysis range. After
all of the available hydrogen is
depleted, a minimal amount of fluid production from the formation will
typically occur.
After pyrolysis of hydrocarbons, a large amount of carbon and some hydrogen
may still be present in the
formation. A significant portion of carbon remaining in the formation can be
produced from the formation in the
form of synthesis gas. Synthesis gas generation may take place during stage 3
heating depicted in FIG. 1. Stage 3
may include heating a hydrocarbon containing formation to a temperature
sufficient to allow synthesis gas
generation. For example, synthesis gas may be produced in a temperature range
from about 400 C to about 1200
C, about 500 C to about 1100 C, or about 550 C to about 1000 C. The
temperature of the heated portion of the
formation when the synthesis gas generating fluid is introduced to the
formation determines the composition of
synthesis gas produced in the formation. The generated synthesis gas may be
removed from the formation through a
production well or production wells.
Total energy content of fluids produced from the hydrocarbon containing
formation may stay relatively
constant throughout pyrolysis and synthesis gas generation. During pyrolysis
at relatively low formation
temperatures, a significant portion of the produced fluid may be condensable
hydrocarbons that have a high energy
content. At higher pyrolysis temperatures, however, less of the formation
fluid may include condensable
hydrocarbons. More non-condensable formation fluids may be produced from the
formation. Energy content per
unit volume of the produced fluid may decline slightly during generation of
predominantly non-condensable
CA 02871784 2014-11-18
formation fluids. During synthesis gas generation, energy content per unit
volume of produced synthesis gas
declines significantly compared to energy content of pyrolyzation fluid. The
volume of the produced synthesis gas,
however, will in many instances increase substantially, thereby compensating
for the decreased energy content.
FIG. 2 depicts a schematic view of an embodiment of a portion of the in situ
heat treatment system for
treating the hydrocarbon containing formation. The in situ heat treatment
system may include barrier wells 200.
Barrier wells are used to form a barrier around a treatment area. The barrier
inhibits fluid flow into and/or out of the
treatment area. Barrier wells include, but are not limited to, dewatering
wells, vacuum wells, capture wells, injection
wells, grout wells, freeze wells, or combinations thereof. In some
embodiments, barrier wells 200 are dewatering
wells. Dewatering wells may remove liquid water and/or inhibit liquid water
from entering a portion of the
formation to be heated, or to the formation being heated. In the embodiment
depicted in FIG. 2, the barrier wells
200 are shown extending only along one side of heat sources 202, but the
barrier wells typically encircle all heat
sources 202 used, or to be used, to heat a treatment area of the formation.
Heat sources 202 are placed in at least a portion of the formation. Heat
sources 202 may include heaters
such as insulated conductors, conductor-in-conduit heaters, surface burners,
flameless distributed combustors, and/or
natural distributed combustors. Heat sources 202 may also include other types
of heaters. Heat sources 202 provide
heat to at least a portion of the formation to heat hydrocarbons in the
formation. Energy may be supplied to heat
sources 202 through supply lines 204. Supply lines 204 may be structurally
different depending on the type of heat
source or heat sources used to heat the formation. Supply lines 204 for heat
sources may transmit electricity for
electric heaters, may transport fuel for combustors, or may transport heat
exchange fluid that is circulated in the
formation. In some embodiments, electricity for an in situ heat treatment
process may be provided by a nuclear
power plant or nuclear power plants. The use of nuclear power may allow for
reduction or elimination of carbon
dioxide emissions from the in situ heat treatment process.
When the formation is heated, the heat input into the formation may cause
expansion of the formation and
geomechanical motion. The heat sources turned on before, at the same time, or
during a dewatering process.
Computer simulations may model formation response to heating. The computer
simulations may be used to develop
a pattern and time sequence for activating heat sources in the formation so
that geomechanical motion of the
formation does not adversely affect the functionality of heat sources,
production wells, and other equipment in the
formation.
Heating the formation may cause an increase in permeability and/or porosity of
the formation. Increases in
permeability and/or porosity may result from a reduction of mass in the
formation due to vaporization and removal
of water, removal of hydrocarbons, and/or creation of fractures. Fluid may
flow more easily in the heated portion of
the formation because of the increased permeability and/or porosity of the
formation. Fluid in the heated portion of
the formation may move a considerable distance through the formation because
of the increased permeability and/or
porosity. The considerable distance may be over 1000 m depending on various
factors, such as permeability of the
formation, properties of the fluid, temperature of the formation, and pressure
gradient allowing movement of the
fluid. The ability of fluid to travel considerable distance in the formation
allows production wells 206 to be spaced
relatively far apart in the formation.
Production wells 206 are used to remove formation fluid from the formation. In
some embodiments,
production well 206 includes a heat source. The heat source in the production
well may heat one or more portions of
the formation at or near the production well. In some in situ heat treatment
process embodiments, the amount of heat
supplied to the formation from the production well per meter of the production
well is less than the amount of heat
applied to the formation from a heat source that heats the formation per meter
of the heat source. Heat applied to the
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CA 02871784 2014-11-18
formation from the production well may increase formation permeability
adjacent to the production well by
vaporizing and removing liquid phase fluid adjacent to the production well
and/or by increasing the permeability of
the formation adjacent to the production well by formation of macro and/or
micro fractures.
More than one heat source may be positioned in the production well. A heat
source in a lower portion of
the production well may be turned off when superposition of heat from adjacent
heat sources heats the formation
sufficiently to counteract benefits provided by heating the formation with the
production well. In some
embodiments, the heat source in an upper portion of the production well may
remain on after the heat source in the
lower portion of the production well is deactivated. The heat source in the
upper portion of the well may inhibit
condensation and reflux of formation fluid.
In some embodiments, the heat source in production well 206 allows for vapor
phase removal of formation
fluids from the formation. Providing heating at or through the production well
may: (1) inhibit condensation and/or
refluxing of production fluid when such production fluid is moving in the
production well proximate the overburden,
(2) increase heat input into the formation, (3) increase production rate from
the production well as compared to a
production well without a heat source, (4) inhibit condensation of high carbon
number compounds (C6 and above) in
the production well, and/or (5) increase formation permeability at or
proximate the production well.
Subsurface pressure in the formation may correspond to the fluid pressure
generated in the formation. As
temperatures in the heated portion of the formation increase, the pressure in
the heated portion may increase as a
result of increased fluid generation and vaporization of water. Controlling
rate of fluid removal from the formation
may allow for control of pressure in the formation. Pressure in the formation
may be determined at a number of
different locations, such as near or at production wells, near or at heat
sources, or at monitor wells.
In some hydrocarbon containing formations, production of hydrocarbons from the
formation is inhibited
until at least some hydrocarbons in the formation have been pyrolyzed.
Formation fluid may be produced from the
formation when the formation fluid is of a selected quality. In some
embodiments, the selected quality includes an
API gravity of at least about 20 , 30 , or 40 . Inhibiting production until at
least some hydrocarbons are pyrolyzed
may increase conversion of heavy hydrocarbons to light hydrocarbons.
Inhibiting initial production may minimize
the production of heavy hydrocarbons from the formation. Production of
substantial amounts of heavy hydrocarbons
may require expensive equipment and/or reduce the life of production
equipment.
In some hydrocarbon containing formations, hydrocarbons in the formation may
be heated to pyrolysis
temperatures before substantial permeability has been generated in the heated
portion of the formation. An initial
lack of permeability may inhibit the transport of generated fluids to
production wells 206. During initial heating,
fluid pressure in the formation may increase proximate heat sources 202. The
increased fluid pressure may be
released, monitored, altered, and/or controlled through one or more heat
sources 202. For example, selected heat
sources 202 or separate pressure relief wells may include pressure relief
valves that allow for removal of some fluid
from the formation.
In some embodiments, pressure generated by expansion of pyrolysis fluids or
other fluids generated in the
formation may be allowed to increase although an open path to production wells
206 or any other pressure sink may
not yet exist in the formation. The fluid pressure may be allowed to increase
towards a lithostatic pressure.
Fractures in the hydrocarbon containing formation may form when the fluid
approaches the lithostatic pressure. For
example, fractures may form from heat sources 202 to production wells 206 in
the heated portion of the formation.
The generation of fractures in the heated portion may relieve some of the
pressure in the portion. Pressure in the
formation may have to be maintained below a selected pressure to inhibit
unwanted production, fracturing of the
overburden or underburden, and/or coking of hydrocarbons in the formation.
32
CA 02871784 2014-11-18
After pyrolysis temperatures are reached and production from the formation is
allowed, pressure in the
formation may be varied to alter and/or control a composition of formation
fluid produced, to control a percentage of
condensable fluid as compared to non-condensable fluid in the formation fluid,
and/or to control an API gravity of
formation fluid being produced. For example, decreasing pressure may result in
production of a larger condensable
fluid component. The condensable fluid component may contain a larger
percentage of olefins.
In some in situ heat treatment process embodiments, pressure in the formation
may be maintained high
enough to promote production of formation fluid with an API gravity of greater
than 200. Maintaining increased
pressure in the formation may inhibit formation subsidence during in situ heat
treatment. Maintaining increased
pressure may facilitate vapor phase production of fluids from the formation.
Vapor phase production may allow for
a reduction in size of collection conduits used to transport fluids produced
from the formation. Maintaining
increased pressure may reduce or eliminate the need to compress formation
fluids at the surface to transport the
fluids in collection conduits to treatment facilities.
Maintaining increased pressure in a heated portion of the formation may
surprisingly allow for production
of large quantities of hydrocarbons of increased quality and of relatively low
molecular weight. Pressure may be
maintained so that formation fluid produced has a minimal amount of compounds
above a selected carbon number.
The selected carbon number may be at most 25, at most 20, at most 12, or at
most 8. Some high carbon number
compounds may be entrained in vapor in the formation and may be removed from
the formation with the vapor.
Maintaining increased pressure in the formation may inhibit entrainment of
high carbon number compounds and/or
multi-ring hydrocarbon compounds in the vapor. High carbon number compounds
and/or multi-ring hydrocarbon
compounds may remain in a liquid phase in the formation for significant time
periods. The significant time periods
may provide sufficient time for the compounds to pyrolyze to form lower carbon
number compounds.
Generation of relatively low molecular weight hydrocarbons is believed to be
due, in part, to autogenous
generation and reaction of hydrogen in a portion of the hydrocarbon containing
formation. For example, maintaining
an increased pressure may force hydrogen generated during pyrolysis into the
liquid phase within the formation.
Heating the portion to a temperature in a pyrolysis temperature range may
pyrolyze hydrocarbons in the formation to
generate liquid phase pyrolyzation fluids. The generated liquid phase
pyrolyzation fluids components may include
double bonds and/or radicals. Hydrogen (H2) in the liquid phase may reduce
double bonds of the generated
pyrolyzation fluids, thereby reducing a potential for polymerization or
formation of long chain compounds from the
generated pyrolyzation fluids. In addition, H2 may also neutralize radicals in
the generated pyrolyzation fluids.
Therefore, H2 in the liquid phase may inhibit the generated pyrolyzation
fluids from reacting with each other and/or
with other compounds in the formation.
Formation fluid produced from production wells 206 may be transported through
collection piping 208 to
treatment facilities 210. Formation fluids may also be produced from heat
sources 202. For example, fluid may be
produced from heat sources 202 to control pressure in the formation adjacent
to the heat sources. Fluid produced
from heat sources 202 may be transported through tubing or piping to
collection piping 208 or the produced fluid
may be transported through tubing or piping directly to treatment facilities
210. Treatment facilities 210 may
include separation units, reaction units, upgrading units, fuel cells,
turbines, storage vessels, and/or other systems
and units for processing produced formation fluids. The treatment facilities
may form transportation fuel from at
least a portion of the hydrocarbons produced from the formation. In some
embodiments, the transportation fuel may
be jet fuel, such as JP-8.
Formation fluid may be hot when produced from the formation through the
production wells. Hot
formation fluid may be produced during solution mining processes and/or during
in situ heat treatment processes. In
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CA 02871784 2014-11-18
some embodiments, electricity may be generated using the heat of the fluid
produced from the formation. Also, heat
recovered from the formation after the in situ process may be used to generate
electricity. The generated electricity
may be used to supply power to the in situ heat treatment process. For
example, the electricity may be used to power
heaters, or to power a refrigeration system for forming or maintaining a low
temperature barrier. Electricity may be
generated using a Kalina cycle or a modified Kalina cycle.
FIG. 3 depicts a schematic representation of a Kalina cycle that uses
relatively high pressure aqua ammonia
as the working fluid. Hot produced fluid from the formation may pass through
line 212 to heat exchanger 214. The
produced fluid may have a temperature greater than about 100 C. Line 216 from
heat exchanger 214 may direct the
produced fluid to a separator or other treatment unit. In some embodiments,
the produced fluid is a mineral
containing fluid produced during solution mining. In some embodiments, the
produced fluid includes hydrocarbons
produced using an in situ heat treatment process or using an in situ
mobilization process. Heat from the produced
fluid is used to evaporate aqua ammonia in heat exchanger 214.
Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 214 and
heat exchanger 222.
Aqua ammonia from heat exchangers 214, 222 passes to separator 224. Separator
224 forms a rich ammonia gas
stream and a lean ammonia gas stream. The rich ammonia gas stream is sent to
turbine 226 to generate electricity.
The lean ammonia gas stream from separator 224 passes through heat exchanger
222. The lean gas stream
leaving heat exchanger 222 is combined with the rich ammonia gas stream
leaving turbine 226. The combination
stream is passed through heat exchanger 228 and returned to tank 218. Heat
exchanger 228 may be water cooled.
Heater water from heat exchanger 228 may be sent to a surface water reservoir
through line 230.
FIG. 4 depicts a schematic representation of a modified Kalina cycle that uses
lower pressure aqua
ammonia as the working fluid. Hot produced fluid from the formation may pass
through line 212 to heat exchanger
214. The produced fluid may have a temperature greater than about 100 C.
Second heat exchanger 232 may further
reduce the temperature of the produced fluid from the formation before the
fluid is sent through line 216 to a
separator or other treatment unit. Second heat exchanger may be water cooled.
Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 234. The
temperature of the aqua
ammonia from tank 218 is heated in heat exchanger 234 by transfer with a
combined aqua ammonia stream from
turbine 226 and separator 224. The aqua ammonia stream from heat exchanger 234
passes to heat exchanger 236.
The temperature of the stream is raised again by transfer of heat with a lean
ammonia stream that exits separator 224.
The stream then passes to heat exchanger 214. Heat from the produced fluid is
used to evaporate aqua ammonia in
heat exchanger 214. The aqua ammonia passes to separator 224.
Separator 224 forms a rich ammonia gas stream and a lean ammonia gas stream.
The rich ammonia gas
stream is sent to turbine 226 to generate electricity. The lean ammonia gas
stream passes through heat exchanger
236. After heat exchanger 236, the lean ammonia gas stream is combined with
the rich ammonia gas stream leaving
turbine 226. The combined gas stream is passed through heat exchanger 234 to
cooler 238. After cooler 238, the
stream returns to tank 218.
In some embodiments, formation fluid produced from the in situ heat treatment
process is sent to a
separator to split the stream into one or more in situ heat treatment process
liquid streams and/or one or more in situ
heat treatment process gas streams. The liquid streams and the gas streams may
be further treated to yield desired
products.
In some embodiments, in situ heat treatment process gas is treated at the site
of the formation to produce
hydrogen. Treatment processes to produce hydrogen from the in situ heat
treatment process gas may include steam
methane reforming, autothermal reforming, and/or partial oxidation reforming.
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CA 02871784 2014-11-18
All or at least a portion of a gas stream may be treated to yield a gas that
meets natural gas pipeline
specifications. FIGS. 5, 6, 7, 8, and 9 depict schematic representations of
embodiments of systems for producing
pipeline gas from the in situ heat treatment process gas stream.
As depicted in FIG. 5, in situ heat treatment process gas 240 enters unit 242.
In unit 242, treatment of in
situ heat treatment process gas 240 removes sulfur compounds, carbon dioxide,
and/or hydrogen to produce gas
stream 244. Unit 242 may include a physical treatment system and/or a chemical
treatment system. The physical
treatment system includes, but is not limited to, a membrane unit, a pressure
swing adsorption unit, a liquid
absorption unit, and/or a cryogenic unit. The chemical treatment system 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, unit 242 uses a Sulfinol gas treatment process
for removal of sulfur compounds.
Carbon dioxide may be removed using Catacarb (Catacarb, Overland Park,
Kansas, U.S.A.) and/or Benfield (UOP,
Des Plaines, Illinois, U.S.A.) gas treatment processes.
Gas stream 244 may include, but is not limited to, hydrogen, carbon monoxide,
methane, and hydrocarbons
having a carbon number of at least 2 or mixtures thereof. In some embodiments,
gas stream 244 includes nitrogen
and/or rare gases such as argon or helium. In some embodiments, gas stream 244
includes from about 0.0001 grams
(g) to about 0.1 g, from about 0.001 g to about 0.05 g, or from about 0.01 g
to about 0.03 g of hydrogen, per gram of
gas stream. In certain embodiments, gas stream 244 includes from about 0.01 g
to about 0.6 g, from about 0.1 g to
about 0.5 g, or from about 0.2 g to 0.4 g of methane, per gram of gas stream.
In some embodiments, gas stream 244 includes from about 0.00001 g to about
0.01 g, from about 0.0005 g
to about 0.005 g, or from about 0.0001 g to about 0.001 g of carbon monoxide,
per gram of gas stream. In certain
embodiments, gas stream 244 includes trace amounts of carbon dioxide.
In certain embodiments, gas stream 244 may include from about 0.0001 g to
about 0.5 g, from about 0.001
g to about 0.2 g, or from about 0.01 g to about 0.1 g of hydrocarbons having a
carbon number of at least 2, per gram
of gas stream. Hydrocarbons having a carbon number of at least 2 include
paraffins and olefins. Paraffins and
olefins include, but are not limited to, ethane, ethylene, acetylene, propane,
propylene, butanes, butylenes, or
mixtures thereof. In some embodiments, hydrocarbons having a carbon number of
at least 2 include from about
0.0001 g to about 0.5 g, from about 0.001 g to about 0.2 g, or from about 0.01
g to about 0.1 g of a mixture of
ethylene, ethane, and propylene. In some embodiments, hydrocarbons having a
carbon number of at least 2 includes
trace amounts of hydrocarbons having a carbon number of at least 4.
Pipeline gas (for example, natural gas) after treatment to remove the hydrogen
sulfide, includes methane,
ethane, propane, butane, carbon dioxide, oxygen, nitrogen, and small amounts
of rare gases. Typically, treated
natural gas includes, per gram of natural gas, about 0.7 g to about 0.98 g of
methane; about 0.0001 g to about 0.2 g
or from about 0.001 g to about 0.05 g of a mixture of ethane, propane, and
butane; about 0.0001 g to about 0.8 g or
from about 0.001 g to about 0.02 g of carbon dioxide; about 0.00001 g to about
0.02 g or from about 0.0001 to about
0.002 of oxygen; trace amounts of rare gases; and the balance being nitrogen.
Such treated natural gas has a heat
content of about 40 MJ/Nm3 to about 50 MJ/Nm3.
Since gas stream 244 differs in composition from treated natural gas, gas
stream 244 may not meet pipeline
gas requirements. Emissions generated during burning of gas stream 244 may be
unacceptable and/or not meet
regulatory standards if the gas stream is to be used as a fuel. Gas stream 244
may include components or amounts of
components that make the gas stream undesirable for use as a feed stream for
making additional products.
In some embodiments, hydrocarbons having a carbon number greater than 2 are
separated from gas stream
244. These hydrocarbons may be separated using cryogenic processes, adsorption
processes, and/or membrane
CA 02871784 2014-11-18
processes. Removal of hydrocarbons having a carbon number greater than 2 from
gas stream 244 may facilitate
and/or enhance further processing of the gas stream.
Process units as described herein may be operated at the following
temperatures, pressures, hydrogen
source flows, and gas stream flows, or operated otherwise as known in the art.
Temperatures may range from about
50 C to about 600 C, from about 100 C to about 500 C, or from about 200 C
to about 400 C. Pressures may
range from about 0.1 MPa to about 20 MPa, from about 1 MPa to about 12 MPa,
from about 4 MPa to about 10
MPa, or from about 6 MPa to about 8 MPa. Flows of gas streams through units
described herein may range from
about 5 metric tons of gas stream per day ("MT/D") to about 15,000 MT/D. In
some embodiments, flows of gas
streams through units described herein range from about 10 MT/D to 10,000 MT/D
or from about 15 MT/D to about
5,000 MT/D. In some embodiments, the hourly volume of gas processed is 5,000
to 25,000 times the volume of
catalyst in one or more processing units.
As depicted in FIG. 5, gas stream 244 and hydrogen source 246 enter
hydrogenation unit 248. Hydrogen
source 246 includes, but is not limited to, hydrogen gas, hydrocarbons, and/or
any compound capable of donating a
hydrogen atom. In some embodiments, hydrogen source 246 is mixed with gas
stream 244 prior to entering
hydrogenation unit 248. In some embodiments, the hydrogen source is hydrogen
and/or hydrocarbons present in gas
= stream 244. In hydrogenation unit 248, contact of gas stream 244 with
hydrogen source 246 in the presence of one
or more catalysts hydrogenates unsaturated hydrocarbons in gas stream 244 and
produces gas stream 250. Gas
stream 250 may include hydrogen and saturated hydrocarbons such as methane,
ethane, and propane. Hydrogenation
unit 248 may include a knock-out pot. The knock-out pot removes any heavy by-
products 252 from the product gas
stream.
Gas stream 250 exits hydrogenation unit 248 and enters hydrogen separation
unit 254. Hydrogen separation
unit 254 is any suitable unit capable of separating hydrogen from the incoming
gas stream. Hydrogen separation
unit 254 may be a membrane unit, a pressure swing adsorption unit, a liquid
absorption unit, or a cryogenic unit. In
certain embodiments, hydrogen separation unit 254 is a membrane unit. Hydrogen
separation unit 254 may include
PRISM membranes available from Air Products and Chemicals, Inc. (Allentown,
Pennsylvania, U.S.A.). The
membrane separation unit may be operated at a temperature ranging from about
50 C to about 80 C (for examples,
at a temperature of about 66 C). In hydrogen separation unit 254, separation
of hydrogen from gas stream 250
produces hydrogen rich stream 256 and gas stream 258. Hydrogen rich stream 256
may be used in other processes,
or, in some embodiments, as hydrogen source 246 for hydrogenation unit 248.
In some embodiments, hydrogen separation unit 254 is a cryogenic unit. When
hydrogen separation unit
254 is a cryogenic unit, gas stream 250 may be separated into a hydrogen rich
stream, a methane rich stream, and/or
a gas stream that contains components having a boiling point greater than or
equal to ethane.
In some embodiments, hydrogen content in gas stream 258 is acceptable and
further separation of hydrogen
from gas stream 258 is not needed. When the hydrogen content in gas stream 258
is acceptable, the gas stream may
be suitable for use as pipeline gas.
Further removal of hydrogen from gas stream 258 may be desired. In some
embodiments, hydrogen is
separated from gas stream 258 using a membrane. An example of a hydrogen
separation membrane is described in
U.S. Patent No. 6,821,501 to Matzakos et al, which is incorporated by
reference as if fully set forth herein.
In some embodiments, a method of removing hydrogen from gas stream 258
includes converting hydrogen
to water. Gas stream 258 exits hydrogen separation unit 254 and enters
oxidation unit 260, as shown in FIG. 5.
Oxidation source 262 also enters oxidation unit 260. In oxidation unit 260,
contact of gas stream 258 with oxidation
source 262 produces gas stream 264. Gas stream 264 may include water produced
as a result of the oxidation. The
36
CA 02871784 2014-11-18
oxidation source may include, but is not limited to, pure oxygen, air, or
oxygen enriched air. Since air or oxygen
enriched air includes nitrogen, monitoring the quantity of air or oxygen
enriched air provided to oxidation unit 260
may be desired to ensure the product gas meets the desired pipeline
specification for nitrogen. Oxidation unit 260
includes, in some embodiments, a catalyst. Oxidation unit 260 is, in some
embodiments, operated at a temperature
in a range from about 50 C to 500 C, from about 100 C to about 400 C, or
from about 200 C to about 300 C.
Gas stream 264 exits oxidation unit 260 and enters dehydration unit 266. In
dehydration unit 266,
separation of water from gas stream 264 produces pipeline gas 268 and water
270. Dehydration unit 266 may be, for
example, a standard gas plant glycol dehydration unit and/or molecular sieves.
In some embodiments, a change in the amount of methane in pipeline gas
produced from an in situ heat
treatment process gas is desired. The amount of methane in pipeline gas may be
enhanced through removal of
components and/or through chemical modification of components in the in situ
heat treatment process gas.
FIG. 6 depicts a schematic representation of an embodiment to enhance the
amount of methane in pipeline
gas through reformation and methanation of the in situ heat treatment process
gas.
Treatment of in situ heat treatment process gas as described herein produces
gas stream 244. Gas stream
244, hydrogen source 246, and steam source 272 enter reforming unit 274. In
some embodiments, gas stream 244,
hydrogen source 246, and/or steam source 272 are mixed together prior to
entering reforming unit 274. In some
embodiments, gas stream 244 includes an acceptable amount of a hydrogen
source, and thus external addition of
hydrogen source 246 is not needed. In reforming unit 274, contact of gas
stream 244 with hydrogen source 246 in
the presence of one or more catalysts and steam source 272 produces gas stream
276. The catalysts and operating
parameters may be selected such that reforming of methane in gas stream 244 is
minimized. Gas stream 276
includes methane, carbon monoxide, carbon dioxide, and/or hydrogen. The carbon
dioxide in gas stream 276, at
least a portion of the carbon monoxide in gas stream 276, and at least a
portion of the hydrogen in gas stream 276 is
from conversion of hydrocarbons with a carbon number greater than 2 (for
example, ethylene, ethane, or propylene)
to carbon monoxide and hydrogen. Methane in gas stream 276, at least a portion
of the carbon monoxide in gas
stream 276, and at least a portion of the hydrogen in gas stream 276 is from
gas stream 244 and hydrogen source
246.
Reforming unit 274 may be operated at temperatures and pressures described
herein, or operated otherwise
as known in the art. In some embodiments, reforming unit 274 is operated at
temperatures ranging from about 250
C to about 500 C. In some embodiments, pressures in reforming unit 274 range
from about I MPa to about 5 MPa.
Removal of excess carbon monoxide in gas stream 276 to meet, for example,
pipeline specifications may be
desired. Carbon monoxide may be removed from gas stream 276 using a
methanation process. Methanation of
carbon monoxide produces methane and water. Gas stream 276 exits reforming
unit 274 and enters methanation unit
278. In methanation unit 278, contact of gas stream 276 with a hydrogen source
in the presence of one or more
catalysts produces gas stream 280. The hydrogen source may be provided by
hydrogen and/or hydrocarbons present
in gas stream 276. In some embodiments, an additional hydrogen source is added
to the methanation unit and/or the
gas stream. Gas stream 280 may include water, carbon dioxide, and methane.
Methanation unit 278 may be operated at temperatures and pressures described
herein or operated otherwise
as known in the art. In some embodiments, methanation unit 278 is operated at
temperatures ranging from about 260
C to about 320 C. In some embodiments, pressures in methanation unit 278
range from about I MPa to about 5
MPa.
Carbon dioxide may be separated from gas stream 280 in carbon dioxide
separation unit 282. In some
embodiments, gas stream 280 exits methanation unit 278 and passes through a
heat exchanger prior to entering
37
CA 02871784 2014-11-18
carbon dioxide separation unit 282. In carbon dioxide separation unit 282,
separation of carbon dioxide from gas
stream 280 produces gas stream 284 and carbon dioxide stream 286. In some
embodiments, the separation process
uses amines to facilitate the removal of carbon dioxide from gas stream 280.
Gas stream 284 includes, in some
embodiments, at most 0.1 g, at most 0.08 g, at most 0.06, or at most 0.04 g of
carbon dioxide per gram of gas stream.
In some embodiments, gas stream 284 is substantially free of carbon dioxide.
Gas stream 284 exits carbon dioxide separation unit 282 and enters dehydration
unit 266. In dehydration
unit 266, separation of water from gas stream 284 produces pipeline gas 268
and water 270.
FIG. 7 depicts a schematic representation of an embodiment to enhance the
amount of methane in pipeline
gas through concurrent hydrogenation and methanation of in situ heat treatment
process gas. Hydrogenation and
methanation of carbon monoxide and hydrocarbons having a carbon number greater
than 2 in the in situ heat
treatment process gas produces methane. Concurrent hydrogenation and
methanation in one processing unit may
inhibit formation of impurities. Inhibiting the formation of impurities
enhances production of methane from the in
situ heat treatment process gas. In some embodiments, the hydrogen source
content of the in situ heat treatment
process gas is acceptable and an external source of hydrogen is not needed.
Treatment of in situ heat treatment process gas as described herein produces
gas stream 244. Gas stream
244 enters hydrogenation and methanation unit 288. In hydrogenation and
methanation unit 288, contact of gas
stream 244 with a hydrogen source in the presence of a catalyst or multiple
catalysts produces gas stream 290. The
hydrogen source may be provided by hydrogen and/or hydrocarbons in gas stream
244. In some embodiments, an
additional hydrogen source is added to hydrogenation and methanation unit 288
and/or gas stream 244. Gas stream
290 may include methane, hydrogen, and, in some embodiments, at least a
portion of gas stream 244. In some
embodiments, gas stream 290 includes from about 0.05 g to about 1 g, from
about 0.8 g to about 0.99 g, or from
about 0.9 g to 0.95 g of methane, per gram of gas stream. Gas stream 290 may
include, per gram of gas stream, at
most 0.1 g of hydrocarbons having a carbon number of at least 2 and at most
0.01 g of carbon monoxide. In some
embodiments, gas stream 290 includes trace amounts of carbon monoxide and/or
hydrocarbons having a carbon
number of at least 2.
Hydrogenation and methanation unit 288 may be operated at temperatures, and
pressures, described herein,
or operated otherwise as known in the art. In some embodiments, hydrogenation
and methanation unit 288 is
operated at a temperature ranging from about 200 C to about 350 C. In some
embodiments, pressure in
hydrogenation and methanation unit 288 is about 2MPa to about 12 MPa, about 4
MPa to about 10 MPa, or about 6
MPa to about 8 MPa. In certain embodiments, pressure in hydrogenation and
methanation unit 288 is about 4 MPa.
The removal of hydrogen from gas stream 290 may be desired. Removal of
hydrogen from gas stream 290
may allow the gas stream to meet pipeline specification and/or handling
requirements.
In FIG. 7, gas stream 290 exits methanation unit 288 and enters polishing unit
292. Carbon dioxide stream
294 also enters polishing unit 292, or it mixes with gas stream 290 upstream
of the polishing unit. In polishing unit
292, contact of the gas stream 290 with carbon dioxide stream 294 in the
presence of one or more catalysts produces
gas stream 296. The reaction of hydrogen with carbon dioxide produces water
and methane. Gas stream 296 may
include methane, water, and, in some embodiments, at least a portion of gas
stream 290. In some embodiments,
polishing unit 292 is a portion of hydrogenation and methanation unit 288 with
a carbon dioxide feed line.
Polishing unit 292 may be operated at temperatures and pressures described
herein, or operated as otherwise
known in the art. In some embodiments, polishing unit 292 is operated at a
temperature ranging from about 200 C
to about 400 C. In some embodiments, pressure in polishing unit 292 is about
2MPa to about 12 MPa, about 4 MPa
38
CA 02871784 2014-11-18
to about 10 MPa, or about 6 MPa to about 8 MPa. In certain embodiments,
pressure in polishing unit 292 is about 4
MPa.
Gas stream 296 enters dehydration unit 266. In dehydration unit 266,
separation of water from gas stream
296 produces pipeline gas 268 and water 270.
FIG. 8 depicts a schematic representation of an embodiment to enhance the
amount of methane in pipeline
gas through concurrent hydrogenation and methanation of in situ heat treatment
process gas in the presence of excess
carbon dioxide and the separation of ethane and heavier hydrocarbons. Hydrogen
not used in the hydrogenation
methanation process may react with carbon dioxide to form water and methane.
Water may then be separated from
the process stream. Concurrent hydrogenation and methanation in the presence
of carbon dioxide in one processing
unit may inhibit formation of impurities.
Treatment of in situ heat treatment process gas as described herein produces
gas stream 244. Gas stream
244 and carbon dioxide stream 294 enter hydrogenation and methanation unit
298. In hydrogenation and
methanation unit 298, contact of gas stream 244 with a hydrogen source in the
presence of one or more catalysts and
carbon dioxide produces gas stream 300. The hydrogen source may be provided by
hydrogen and/or hydrocarbons
in gas stream 244. In some embodiments, the hydrogen source is added to
hydrogenation and methanation unit 298
or to gas stream 244. The quantity of hydrogen in hydrogenation and
methanation unit 298 may be controlled and/or
the flow of carbon dioxide may be controlled to provide a minimum quantity of
hydrogen in gas stream 300.
Gas stream 300 may include water, hydrogen, methane, ethane, and, in some
embodiments, at least a
portion of the hydrocarbons having a carbon number greater than 2 from gas
stream 244. In some embodiments, gas
stream 300 includes from about 0.05 g to about 0.7 g, from about 0.1 g to
about 0.6 g, or from about 0.2 g to 0.5 g of
methane, per gram of gas stream. Gas stream 300 includes from about 0.0001 g
to about 0.4 g, from about 0.001 g
to about 0.2 g, or from about 0.01 g to 0.1 g of ethane, per gram of gas
stream. In some embodiments, gas stream
300 includes a trace amount of carbon monoxide and olefins.
Hydrogenation and methanation unit 298 may be operated at temperatures and
pressures, described herein,
or operated otherwise as known in the art. In some embodiments, hydrogenation
and methanation unit 298 is
operated at a temperature ranging from about 60 C to about 350 C and a
pressure ranging from about 1 MPa to
about 12 MPa, about 2MPa to about 10 MPa, or about 4MPa to about 8 MPa.
In some embodiments, separation of ethane from methane is desirable.
Separation may be performed using
membrane and/or cryogenic techniques. Cryogenic processes may require that
water levels in a gas stream be at
most 1-10 part per million by weight.
Water in gas stream 300 may be removed using generally known water removal
techniques. Gas stream
300 exits hydrogenation and methanation unit 298, passes through heat
exchanger 302 and then enters dehydration
unit 266. In dehydration unit 266, separation of water from gas stream 300 as
previously described, as well as by
contact with absorption units and/or molecular sieves, produces gas stream 304
and water 270. Gas stream 304 may
have a water content of at most 10 ppm, at most 5 ppm, or at most 1 ppm. In
some embodiments, water content in
gas stream 304 ranges from about 0.01 ppm to about 10 ppm, from about 0.05 ppm
to about 5 ppm, or from about
0.1 ppm to about 1 ppm.
Cryogenic separator 306 separates gas stream 304 into pipeline gas 268 and
hydrocarbon stream 308.
Pipeline gas stream 268 includes methane and/or carbon dioxide. Hydrocarbon
stream 308 includes ethane and, in
some embodiments, residual hydrocarbons having a carbon number of at least 2.
In some embodiments,
hydrocarbons having a carbon number of at least 2 may be separated into ethane
and additional hydrocarbons and/or
sent to other operating units.
39
CA 02871784 2014-11-18
FIG. 9 depicts a schematic representation of an embodiment to enhance the
amount of methane in pipeline
gas through concurrent hydrogenation and methanation of in situ heat treatment
process gas in the presence of excess
hydrogen. The use of excess hydrogen during the hydrogenation and methanation
process may prolong catalyst life,
control reaction rates, and/or inhibit formation of impurities.
Treatment of in situ heat treatment process gas as described herein produces
gas stream 244. Gas stream
244 and hydrogen source 246 enter hydrogenation and methanation unit 310. In
some embodiments, hydrogen
source 246 is added to gas stream 244. In hydrogenation and methanation unit
310, contact of gas stream 244 with
hydrogen source 246 in the presence of one or more catalysts produces gas
stream 312. In some embodiments,
carbon dioxide may be added to hydrogen and methanation unit 310. The quantity
of hydrogen in hydrogenation and
methanation unit 310 may be controlled to provide an excess quantity of
hydrogen to the hydrogenation and
methanation unit.
Gas stream 312 may include water, hydrogen, methane, ethane, and, in some
embodiments, at least a
portion of the hydrocarbons having a carbon number greater than 2 from gas
stream 244. In some embodiments, gas
stream 312 includes from about 0.05 g to about 0.9 g, from about 0.1 g to
about 0.6 g, or from about 0.2 g to 0.5 g of
methane, per gram of gas stream. Gas stream 312 includes from about 0.0001 g
to about 0.4 g, from about 0.001 g
to about 0.2 g, or from about 0.01 g to 0.1 g of ethane, per gram of gas
stream. In some embodiments, gas stream
312 includes carbon monoxide and trace amounts of olefins.
Hydrogenation and methanation unit 310 may be operated at temperatures and
pressures, described herein,
or operated otherwise as known in the art. In some embodiments, hydrogenation
and methanation unit 310 is
operated at a temperature ranging from about 60 C to about 400 C and a
hydrogen partial pressure ranging from
about 1 MPa to about 12 MPa, about 2 MPa to about 8 MPa, or about 3 MPa to
about 5 MPa. In some embodiments,
the hydrogen partial pressure in hydrogenation and methanation unit 310 is
about 3 MPa.
Gas stream 312 enters gas separation unit 314. Gas separation unit 314 is any
suitable unit or combination
of units that is capable of separating hydrogen and/or carbon dioxide from gas
stream 312. Gas separation unit may
be a pressure swing adsorption unit, a membrane unit, a liquid absorption
unit, and/or a cryogenic unit. In some
embodiments, gas stream 312 exits hydrogenation and methanation unit 310 and
passes through a heat exchanger
prior to entering gas separation unit 314. In gas separation unit 314,
separation of hydrogen from gas stream 312
produces gas stream 316 and hydrogen stream 318. Hydrogen stream 318 may be
recycled to hydrogenation and
methanation unit 310, mixed with gas stream 244 and/or mixed with hydrogen
source 246 upstream of the
hydrogenation methanation unit. In embodiments in which carbon dioxide is
added to hydrogenation and
methanation unit 310, carbon dioxide is separated from gas stream 316 in
separation unit 314. The separated carbon
dioxide may be recycled to the hydrogenation and methanation unit, mixed with
gas stream 244 upstream of the
hydrogenation and methanation unit, and/or mixed with the carbon dioxide
stream entering the hydrogenation and
methanation unit.
Gas stream 316 enters dehydration unit 266. In dehydration unit 266,
separation of water from gas stream
316 produces pipeline gas 268 and water 270.
It should be understood that gas stream 244 may be treated by combinations of
one or more of the processes
described in FIGS. 5, 6, 7, 8, and 9. For example, all or at least a portion
of gas streams from reforming unit 274
(FIG. 6) may be treated in hydrogenation and methanation units 288 (FIG. 7),
298 (FIG. 8), or 308 (FIG. 9). All or
at least a portion of the gas stream produced from hydrogenation unit 248 may
enter, or be combined with gas
streams entering, reforming unit 274, hydrogenation and methanation unit 288,
and/or hydrogenation and
CA 02871784 2014-11-18
methanation unit 298. In some embodiments, gas stream 244 may be hydrotreated
and/or used in other processing
units.
Catalysts used to produce natural gas that meets pipeline specifications may
be bulk metal catalysts or
supported catalysts. Bulk metal catalysts include Columns 6-10 metals.
Supported catalysts include Columns 6-10
metals on a support. Columns 6-10 metals include, but are not limited to,
vanadium, chromium, molybdenum,
tungsten, manganese, technetium, rhenium, iron, cobalt, nickel, ruthenium,
palladium, rhodium, osmium, iridium,
platinum, or mixtures thereof. The catalyst may have, per gram of catalyst, a
total Columns 6-10 metals content of at
least 0.0001 g, at least 0.001 g, at least 0.01 g, or in a range from about
0.0001-0.6 g, about 0.005-0.3 g, about 0.001-
0.1 g, or about 0.01-0.08 g. In some embodiments, the catalyst includes a
Column 15 element in addition to the
Columns 6-10 metals. An example of a Column 15 element is phosphorus. The
catalyst may have a total Column
elements content, per gram of catalyst, in a range from about 0.000001-0.1 g,
about 0.00001-0.06 g, about
0.00005-0.03 g, or about 0.0001-0.001 g. In some embodiments, the catalyst
includes a combination of Column 6
metals with one or more Columns 7-10 metals. A molar ratio of Column 6 metals
to Columns 7-10 metals may be in
a range from 0.1-20, 1-10, or 2-5. In some embodiments, the catalyst includes
Column 15 elements in addition to
15 the combination of Column 6 metals with one or more Columns 7-10 metals.
In some embodiments, Columns 6-10 metals are incorporated in, or deposited on,
a support to form the
catalyst. In certain embodiments, Columns 6-10 metals in combination with
Column 15 elements are incorporated
in, or deposited on, the support to form the catalyst. In embodiments in which
the metals and/or elements are
supported, the weight of the catalyst includes all support, all metals, and
all elements. The support may be porous
and may include refractory oxides; oxides of tantalum, niobium, vanadium,
scandium, or lanthanide metals; porous
carbon based materials; zeolites; or combinations thereof. Refractory oxides
may include, but are not limited to,
alumina, silica, silica-alumina, titanium oxide, zirconium oxide, magnesium
oxide, or mixtures thereof. Supports
may be obtained from a commercial manufacturer such as CR1/Criterion Inc.
(Houston, Texas, U.S.A.). Porous
carbon based materials include, but are not limited to, activated carbon
and/or porous graphite. Examples of zeolites
include Y-zeolites, beta zeolites, mordenite zeolites, ZSM-5 zeolites, and
ferrierite zeolites. Zeolites may be
obtained from a commercial manufacturer such as Zeolyst (Valley Forge,
Pennsylvania, U.S.A.).
Supported catalysts may be prepared using generally known catalyst preparation
techniques. Examples of
catalyst preparations are described in U.S. Patent Nos. 6,218,333 to Gabrielov
et al.; 6,290,841 to Gabrielov et al.;
5,744,025 to Boon et al., and 6,759,364 to Bhan, all of which are incorporated
by reference herein.
In some embodiments, the support is impregnated with metal to form the
catalyst. In certain embodiments,
the support is heat treated at temperatures in a range from about 400 C to
about 1200 C, from about 450 C to
about 1000 C, or from about 600 C to about 900 C prior to impregnation with
a metal. In some embodiments,
impregnation aids are used during preparation of the catalyst. Examples of
impregnation aids include a citric acid
component, ethylenediaminetetraacetic acid (EDTA), ammonia, or mixtures
thereof.
The Columns 6-10 metals and support may be mixed with suitable mixing
equipment to form a Columns 6-
10 metals/support mixture. The Columns 6-10 metals/support mixture may be
mixed using suitable mixing
equipment. Examples of suitable mixing equipment include tumblers, stationary
shells or troughs, Muller mixers
(batch type or continuous type), impact mixers, and any other generally known
mixer, or other device, that will
suitably provide the Columns 6-10 metals support mixture. In certain
embodiments, the materials are mixed until
the Columns 6-10 metals are substantially homogeneously dispersed in the
support.
In some embodiments, the catalyst is heat treated at temperatures from 150-750
C, from 200-740 C, or
from 400-730 C after combining the support with the metal. In some
embodiments, the catalyst is heat treated in
41
CA 02871784 2014-11-18
the presence of hot air and/or oxygen rich air at a temperature in a range
between 400 C and 1000 C to remove
volatile matter and/or to convert at least a portion of the Columns 6-10
metals to the corresponding metal oxide.
In other embodiments, a catalyst precursor is heat treated in the presence of
air at temperatures in a range
from 35-500 C for a period of time in a range from 1-3 hours to remove a
majority of the volatile components
without converting the Columns 6-10 metals to the corresponding metal oxide.
Catalysts prepared by such a method
are generally referred to as "uncalcined" catalysts. When catalysts are
prepared in this manner, in combination with
a sulfiding method, the active metals may be substantially dispersed in the
support. Preparations of such catalysts
are described in U.S. Patent Nos. 6,218,333 to Gabrielov et al., and 6,290,841
to Gabrielov et al.
In some embodiments, the catalyst and/or a catalyst precursor is sulfided to
form metal sulfides (prior to
use) using techniques known in the art (for example, ACT1CATTm process, CRI
International, Inc. (Houston, Texas,
U.S.A.)). In some embodiments, the catalyst is dried then sulfided.
Alternatively, the catalyst may be sulfided in
situ by contact of the catalyst with a gas stream that includes sulfur-
containing compounds. In situ sulfurization may
utilize either gaseous hydrogen sulfide in the presence of hydrogen or liquid-
phase sulfurizing agents such as
organosulfur compounds (including alkylsulfides, polysulfides, thiols, and
sulfoxides). Ex-situ sulfurization
processes are described in U.S. Patent Nos. 5,468,372 to Seamans et al., and
5,688,736 to Seamans et al., all of
which are incorporated by reference herein.
In some embodiments, a first type of catalyst ("first catalyst") includes
Columns 6-10 metals and the
support. The first catalyst is, in some embodiments, an uncalcined catalyst.
In some embodiments, the first catalyst
includes molybdenum and nickel. In certain embodiments, the first catalyst
includes phosphorus. In some
embodiments, the first catalyst includes Columns 9-10 metals on a support. The
Column 9 metal may be cobalt and
the Column 10 metal may be nickel. In some embodiments, the first catalyst
includes Columns 10-11 metals. The
Column 10 metal may be nickel and the Column 11 metal may be copper.
The first catalyst may assist in the hydrogenation of olefins to alkanes. In
some embodiments, the first
catalyst is used in the hydrogenation unit. The first catalyst may include at
least 0.1 g, at least 0.2 g, or at least 0.3 g
of Column 10 metals per gram of support. In some embodiments, the Column 10
metal is nickel. In certain
embodiments, the Column 10 metal is palladium and/or a mixed alloy of platinum
and palladium. Use of a mixed
alloy catalyst may enhance processing of gas streams with sulfur containing
compounds. In some embodiments, the
first catalyst is a commercial catalyst. Examples of commercial first
catalysts include, but are not limited to,
Criterion 424, DN-I40, DN-200, and DN-3100, KL6566, KL6560, KL6562, KL6564,
KL7756; KL7762, KL7763,
KL7731, C-624, C654, all of which are available from CRI/Criterion Inc.
In some embodiments, a second type of catalyst ("second catalyst") includes
Column 10 metal on a support.
The Column 10 metal may be platinum and/or palladium. In some embodiments, the
catalyst includes about 0.001 g
to about 0.05 g, or about 0.01 g to about 0.02 g of platinum ancUor palladium
per gram of catalyst. The second
catalyst may assist in the oxidation of hydrogen to form water. In some
embodiments, the second catalyst is used in
the oxidation unit. In some embodiments, the second catalyst is a commercial
catalyst. An example of commercial
second catalyst includes KL87748, available from CRI/Criterion Inc.
In some embodiments, a third type of catalyst ("third catalyst") includes
Columns 6-10 metals on a support.
In some embodiments, the third catalyst includes Columns 9-10 metals on a
support. The Column 9 metal may be
cobalt and the Column 10 metal may be nickel. In some embodiments, the content
of nickel metal is from about 0.1
g to about 0.3 g, per gram of catalyst. The support for a third catalyst may
include zirconia. The third catalyst may
assist in the reforming of hydrocarbons having a carbon number greater than 2
to carbon monoxide and hydrogen.
The third catalyst may be used in the reforming unit. In some embodiments, the
third catalyst is a commercial
42
CA 02871784 2014-11-18
catalyst. Examples of commercial third catalysts include, but are not limited
to, CRG-FR and/or CRG-LH available
from Johnson Matthey (London, England).
In some embodiments, a fourth type of catalyst ("fourth catalyst") includes
Columns 6-10 metals on a
support. In some embodiments, the fourth catalyst includes Column 8 metals in
combination with Column 10 metals
on a support. The Column 8 metal may be ruthenium and the Column 10 metal may
be nickel, palladium, platinum,
or mixtures thereof. In some embodiments, the fourth catalyst support includes
oxides of tantalum, niobium,
vanadium, the lanthanides, scandium, or mixtures thereof. The fourth catalyst
may be used to convert carbon
monoxide and hydrogen to methane and water. In some embodiments, the fourth
catalyst is used in the methanation
unit. In some embodiments, the fourth catalyst is a commercial catalyst.
Examples of commercial fourth catalysts,
include, but are not limited to, KATALCO 11-4 and/or KATALCO 11-4R available
from Johnson Matthey.
In some embodiments, a fifth type of catalyst ("fifth catalyst") includes
Columns 6-10 metals on a support.
In some embodiments, the fifth catalyst includes a Column 10 metal. The fifth
catalyst may include from about 0.1
g to about 0.99 g, from about 0.3 g to about 0.9 g, from about 0.5 g to about
0.8 g, or from 0.6 g to about 0.7 g of
Column 10 metal per gram of fifth catalyst. In some embodiments, the Column 10
metal is nickel. In some
embodiments, a catalyst that has at least 0.5 g of nickel per gram of fifth
catalyst has enhanced stability in a
hydrogenation and methanation process. The fifth catalyst may assist in the
conversion of hydrocarbons and carbon
dioxide to methane. The fifth catalyst may be used in hydrogenation and
methanation units and/or polishing units.
In some embodiments, the fifth catalyst is a commercial catalyst. An example
of a commercial fifth catalyst is
KL6524-T, available from CRI/Criterion Inc.
Heating a portion of the subsurface formation may cause the mineral structure
of the formation to change
and form particles. The particles may be dispersed and/or become partially
dissolved in the formation fluid. The
particles may include metals and/or compounds of metals from Columns 1-2 and
Columns 4-13 of the Periodic
Table (for example, aluminum, silicon, magnesium, calcium, potassium sodium,
beryllium, lithium, chromium,
magnesium, copper, zirconium, and so forth). In certain embodiments, the
particles include cenospheres. In some
embodiments, the particles are coated, for example, with hydrocarbons of the
formation fluid. In certain
embodiments, the particles include zeolites.
A concentration of particles in formation fluid may range from about 1 ppm to
about 3000 ppm, from about
50 ppm to about 2000 ppm, or from about 100 ppm to about 1000 ppm. The size of
particles may range from about
0.5 micrometers to about 200 micrometers, from about 5 micrometers to about
150 micrometers, from about 10
micrometers to about 100 micrometers, or about 20 micrometers to about 50
micrometers.
In certain embodiments, formation fluid may include a distribution of
particles. The distribution of
particles may be, but is not limited to, a trimodal or a bimodal distribution.
For example, a trimodal distribution of
particles may include from about 1 ppm to about 50 ppm of particles with a
size of about 5 micrometers to about 10
micrometers, from about 2 ppm to about 2000 ppm of particles with a size of
about 50 micrometers to about 80
micrometers, and from about 1 ppm to about 100 ppm with a size of between
about 100 micrometers and about 200
micrometers. A bimodal distribution of particles may include from about 1 ppm
to about 60 ppm of particles with a
size of between about 50 micrometers and about 60 micrometers and from about 2
ppm to about 2000 ppm of
particles with a size between about 100 micrometers and about 200 micrometers.
In some embodiments, the particles may contact the formation fluid and
catalyze formation of compounds
having a carbon number of at most 25, at most 20, at most 12, or at most 8. In
certain embodiments, zeolitic
particles may assist in the oxidation and/or reduction of formation fluids to
produce compounds not generally found
43
CA 02871784 2014-11-18
in fluids produced using conventional production methods. Contact of formation
fluid with hydrogen in the presence
of zeolitic particles may catalyze reduction of double bond compounds in the
formation fluid.
In some embodiments, all or a portion of the particles in the produced fluid
may be removed from the
produced fluid. The particles may be removed by using a centrifuge, by
washing, by acid washing, by filtration, by
electrostatic precipitation, by froth flotation, and/or by another type of
separation process.
Formation fluid produced from the in situ heat treatment process may be sent
to the separator to split the
stream into the in situ heat treatment process liquid stream and an in situ
heat treatment process gas stream. The
liquid stream and the gas stream may be further treated to yield desired
products. When the liquid stream is treated
using generally known conditions to produce commercial products, processing
equipment may be adversely affected.
For example, the processing equipment may clog. Examples of processes to
produce commercial products include,
but are not limited to, alkylation, distillation, catalytic reforming
hydrocracking, hydrotreating, hydrogenation,
hydrodesulfurization, catalytic cracking, delayed coking, gasification, or
combinations thereof. Processes to produce
commercial products are described in "Refining Processes 2000," Hydrocarbon
Processing, Gulf Publishing Co., pp.
87-142, which is incorporated by reference herein. Examples of commercial
products include, but are not limited to,
diesel, gasoline, hydrocarbon gases, jet fuel, kerosene, naphtha, vacuum gas
oil ("VGO"), or mixtures thereof.
Process equipment may become clogged or fouled by compositions in the in situ
heat treatment process
liquid. Clogging compositions may include, but are not limited to,
hydrocarbons and/or solids produced from the in
situ heat treatment process. Compositions that cause clogging may be formed
during heating of the in situ heat
treatment process liquid. The compositions may adhere to parts of the
equipment and inhibit the flow of the liquid
stream through processing units.
Solids that cause clogging may include, but are not limited to, organometallic
compounds, inorganic
compounds, minerals, mineral compounds, cenospheres, coke, semi-soot, and/or
mixtures thereof. The solids may
have a particle size such that conventional filtration may not remove the
solids from the liquid stream.
Hydrocarbons that cause clogging may include, but are not limited to,
hydrocarbons that contain heteroatoms,
aromatic hydrocarbons, cyclic hydrocarbons, cyclic di-olefins, and/or acyclic
di-olefins. In some embodiments,
solids and/or hydrocarbons present in the in situ heat treatment process
liquid that cause clogging are partially
soluble or insoluble in the situ heat treatment process liquid. In some
embodiments, conventional filtration of the
liquid stream prior to or during heating is insufficient and/or ineffective
for removal of all or some of the
compositions that clog process equipment.
In some embodiments, clogging compositions are at least partially removed from
the liquid stream by
washing and/or desalting the liquid stream. In some embodiments, clogging of
process equipment is inhibited by
filtering at least a portion of the liquid stream through a nanofiltration
system. In some embodiments, clogging of
process equipment is inhibited by hydrotreating at least a portion of the
liquid stream. In some embodiments, at least
a portion the liquid stream is nanofiltered and then hydrotreated to remove
composition that may clog and/or foul
process equipment. The hydrotreated and/or nanofiltered liquid stream may be
further processed to produce
commercial products. In some embodiments, anti-fouling additives are added to
the liquid stream to inhibit clogging
of process equipment. Anti-fouling additives are described in U.S. Patent Nos.
5,648,305 to Mansfield et al.;
5,282,957 to Wright et al.; 5,173,213 to Miller et al.; 4,840,720 to Reid;
4,810,397 to Dvoracek; and 4,551,226 to
Fern, all of which are incorporated by reference herein. Examples of
commercially available additives include, but
are not limited to, Chimec RU 303 Chimec RU 304, Chimec RU 305, Chimec RU 306,
Chimec RU 307, Chimec RU
308, (available from Chimec, Rome, Italy), GE-Betz Thermal Flow 7R29 GE-Betz
ProChem 3F28, Ge Betz
ProChem 3F18 (available from GE Water and Process Technologies, Trevose, PA,
U.S.A.).
44
CA 02871784 2014-11-18
FIG. 10 depicts a schematic representation of an embodiment of a system for
producing crude products
and/or commercial products from the in situ heat treatment process liquid
stream and/or the in situ heat treatment
process gas stream. Formation fluid 320 enters fluid separation unit 322 and
is separated into in situ heat treatment
process liquid stream 324, in situ heat treatment process gas 240 and aqueous
stream 326. In some embodiments,
fluid separation unit 322 includes a quench zone. As produced formation fluid
enters the quench zone, quenching
fluid such as water, nonpotable water and/or other components may be added to
the formation fluid to quench and/or
cool the formation fluid to a temperature suitable for handling in downstream
processing equipment. Quenching the
formation fluid may inhibit formation of compounds that contribute to physical
and/or chemical instability of the
fluid (for example, inhibit formation of compounds that may precipitate from
solution, contribute to corrosion,
and/or fouling of downstream equipment and/or piping). The quenching fluid may
be introduced into the formation
fluid as a spray and/or a liquid stream. In some embodiments, the formation
fluid is introduced into the quenching
fluid. In some embodiments, the formation fluid is cooled by passing the fluid
through a heat exchanger to remove
some heat from the formation fluid. The quench fluid may be added to the
cooled formation fluid when the
temperature of the formation fluid is near or at the dew point of the quench
fluid. Quenching the formation fluid
near or at the dew point of the quench fluid may enhance solubilization of
salts that may cause chemical and/or
physical instability of the quenched fluid (for example, ammonium salts). In
some embodiments, an amount of
water used in the quench is minimal so that salts of inorganic compounds
and/or other components do not separate
from the mixture. In separation unit 322, at least a portion of the quench
fluid may be separated from the quench
mixture and recycled to the quench zone with a minimal amount of treatment.
Heat produced from the quench may
be captured and used in other facilities. In some embodiments, vapor may be
produced during the quench. The
produced vapor may be sent to gas separation unit 328 and/or sent to other
facilities for processing.
In situ heat treatment process gas 240 may enter gas separation unit 328 to
separate gas hydrocarbon stream
330 from the in situ heat treatment process gas. The gas separation unit is,
in some embodiments, a rectified
adsorption and high pressure fractionation unit. Gas hydrocarbon stream 330
includes hydrocarbons having a carbon
number of at least 3.
In situ heat treatment process liquid stream 324 enters liquid separation unit
332. In some embodiments,
liquid separation unit 332 is not necessary. In liquid separation unit 332,
separation of in situ heat treatment process
liquid stream 324 produces gas hydrocarbon stream 336 and salty process liquid
stream 338. Gas hydrocarbon
stream 336 may include hydrocarbons having a carbon number of at most 5. A
portion of gas hydrocarbon stream
336 may be combined with gas hydrocarbon stream 330. Salty process liquid
stream 338 may be processed through
desalting unit 340 to form liquid stream 334. Desalting unit 340 removes
mineral salts and/or water from salty
process liquid stream 338 using known desalting and water removal methods. In
certain embodiments, desalting unit
340 is upstream of liquid separation unit 332.
Liquid stream 334 includes, but is not limited to, hydrocarbons having a
carbon number of at least 5 and/or
hydrocarbon containing heteroatoms (for example, hydrocarbons containing
nitrogen, oxygen, sulfur, and
phosphorus). Liquid stream 334 may include at least 0.001 g, at least 0.005 g,
or at least 0.01 g of hydrocarbons
with a boiling range distribution between 95 C and 200 C at 0.101 MPa; at
least 0.01 g, at least 0.005 g, or at least
0.001 g of hydrocarbons with a boiling range distribution between 200 C and
300 C at 0.101 MPa; at least 0.001 g,
at least 0.005 g, or at least 0.01 g of hydrocarbons with a boiling range
distribution between 300 C and 400 C at
0.101 MPa; and at least 0.001 g, at least 0.005 g, or at least 0.01 g of
hydrocarbons with a boiling range distribution
between 400 C and 650 C at 0.101 MPa. In some embodiments, liquid stream 334
contains at most 10% by weight
water, at most 5% by weight water, at most 1% by weight water, or at most 0.1%
by weight water.
CA 02871784 2014-11-18
After exiting desalting unit 340, liquid stream 334 enters filtration system
342. In some embodiments,
filtration system 342 is connected to the outlet of the desalting unit.
Filtration system 342 separates at least a portion
of the clogging compounds from liquid stream 334. In some embodiments,
filtration system 342 is skid mounted.
Skid mounting filtration system 342 may allow the filtration system to be
moved from one processing unit to
another. In some embodiments, filtration system 342 includes one or more
membrane separators, for example, one
or more nanofiltration membranes or one or more reserve osmosis membranes.
The membrane may be a ceramic membrane and/or a polymeric membrane. The
ceramic membrane may
be a ceramic membrane having a molecular weight cut off of at most 2000
Daltons (Da), at most 1000 Da, or at most
500 Da. Ceramic membranes do not have to swell in order to work under optimal
conditions to remove the desired
materials from a substrate (for example, clogging compositions from the liquid
stream). In addition, ceramic
membranes may be used at elevated temperatures. Examples of ceramic membranes
include, but are not limited to,
mesoporous titania, mesoporous gamma-alumina, mesoporous zirconia, mesoporous
silica, and combinations
thereof.
The polymeric membrane includes a top layer made of a dense membrane and a
base layer (support) made
of a porous membrane. The polymeric membrane may be arranged to allow the
liquid stream (permeate) to flow
first through the dense membrane top layer and then through the base layer so
that the pressure difference over the
membrane pushes the top layer onto the base layer. The polymeric membrane is
organophilic or hydrophobic
membrane so that water present in the liquid stream is retained or
substantially retained in the retentate.
The dense membrane layer may separate at least a portion of or substantially
all of the clogging
compositions from liquid stream 334. In some embodiments, the dense polymeric
membrane has properties such
that liquid stream 334 passes through the membrane by dissolving in and
diffusing through its structure. At least a
portion of the clogging particles may not dissolve and/or diffuse through the
dense membrane, thus they are
removed. The clogging particles may not dissolve and/or diffuse through the
dense membrane because of the
complex structure of the clogging particles and/or their high molecular
weight. The dense membrane layer may
include a cross-linked structure as described in WO 96/27430 to Schmidt et
al., which is incorporated by reference
herein. A thickness of the dense membrane layer may range from a 1 micrometer
to 15 micrometers, from 2
micrometers to 10 micrometers, or from 3 micrometers to 5 micrometers.
The dense membrane may be made from polysiloxane, poly-di-methyl siloxane,
poly-octyl-methyl siloxane,
polyimide, polyaramide, poly-tri-methyl silyl propyne, or mixtures thereof.
Porous base layers may be made of
materials that provide mechanical strength to the membrane and may be any
porous membrane used for ultra
filtration, nanofiltration, or reverse osmosis. Examples of such materials are
polyacrylonitrile, polyamideimide in
combination with titanium oxide, polyetherimide, polyvinylidenediflouroide,
polytetrafluoroethylene or
combinations thereof.
During separation of clogging compositions from liquid stream 334, the
pressure difference across the
membrane may range from about 0.5 MPa to about 6 MPa, from about 1 MPa to
about5 MPa, or from about 2 MPa
to about 4 MPa. A temperature of separation may range from the pour point of
the liquid stream up to 100 C, from
about -20 C to about 100 C, from about 10 C to about 90 C, or from about
20 C to about 85 C. During a
continuous operation, the permeate flux rate may be at most 50% of the initial
flux, at most 70% of the initial flux, or
at most 90% of the initial flux. A weight recovery of the permeate on feed may
range from about 50% by weight to
97% by weight, from about 60% by weight to 90% by weight, or from about 70% by
weight to 80% by weight.
Filtration system 342 may include one or more membrane separators. The
membrane separators may
include one or more membrane modules. When two or more membrane separators are
used, they may be arranged in
46
CA 02871784 2014-11-18
a parallel configuration to allow feed (retentate) from a first membrane
separator to flow into a second membrane
separator. Examples of membrane modules include, but are not limited to,
spirally wound modules, plate and frame
modules, hollow fibers, and tubular modules. Membrane modules are described in
Encyclopedia of Chemical
Engineering, 4th Ed., 1995, John Wiley & Sons Inc., Vol. 16, pages 158-164.
Examples of spirally wound modules
are described in, for example, W0/2006/040307 to Boestert et al., U.S. Patent
No. 5,102,551 to Pasternak; 5,093,002
to Pasternak; 5,275,726 to Feimer et al.; 5,458,774 to Mannapperuma; and
5,150,118 to Finkle et al, all of which are
incorporated by reference herein.
In some embodiments, a spirally wound module is used when a dense membrane is
used in filtration system
342. A spirally wound module may include a membrane assembly of two membrane
sheets between which a
permeate spacer sheet is sandwiched, and which membrane assembly is sealed at
three sides. The fourth side is
connected to a permeate outlet conduit such that the area between the
membranes in fluid communication with the
interior of the conduit. On top of one of the membranes a feed spacer sheet is
arranged, and the assembly with feed
spacer sheet is rolled up around the permeate outlet conduit, to form a
substantially cylindrical spirally wound
membrane module. The feed spacer may have a thickness of at least 0.6 mm, at
least 1 mm, or at least 3 mm to
allow sufficient membrane surface to be packed into a spirally wound module.
In some embodiments, the feed
spacer is a woven feed spacer. During operation, a feed mixture may be passed
from one end of the cylindrical
module between the membrane assemblies along the feed spacer sheet sandwiched
between feed sides of the
membranes. Part of the feed mixture passes through either one of the membrane
sheets to the permeate side. The
resulting permeate flows along the permeate spacer sheet into the permeate
outlet conduit.
In some embodiments, the membrane separation is a continuous process. Liquid
stream 334 passes over the
membrane due to a pressure difference to obtain a filtered liquid stream 344
(permeate) and/or recycle liquid stream
346 (retentate). In some embodiments, filtered liquid stream 344 may have
reduced concentrations of compositions
and/or particles that cause clogging in downstream processing systems.
Continuous recycling of recycle liquid
stream 346 through nanofiltration system can increase the production of
filtered liquid stream 344 to as much as 95%
of the original volume of liquid stream 334. Recycle liquid stream 346 may be
continuously recycled through a
spirally wound membrane module for at least 10 hours, for at least one day, or
for at least one week without cleaning
the feed side of the membrane. Upon completion of the filtration, waste stream
348 (retentate) may include a high
concentration of compositions and/or particles that cause clogging. Waste
stream 348 exits filtration system 342 and
is transported to other processing units such as, for example, a delayed
coking unit and/or a gasification unit.
Filtered liquid stream 344 may exit filtration system 342 and enter one or
more process units. Process units
as described herein for the production of crude products and/or commercial
products may be operated at the
following temperatures, pressures, hydrogen source flows, liquid stream flows,
or combinations thereof, or operated
otherwise as known in the art. Temperatures range from about 200 C to about
900 C, from about 300 C to about
800 C, or from about 400 C to about 700 C. Pressures range from about 0.1
MPa to about 20 MPa, from about 1
MPa to about 12 MPa, from about 4 MPa to about 10 MPa, or from about 6 MPa to
about 8 MPa. Liquid hourly
space velocities of the liquid stream range from about 0.1 lit to about 30 If%
from about 0.5 h1 to about 25 h'1, from
about 1111 to about 2011-1, from about 1.5111 to about 15 WI, or from about 2
h1 to about 10 WI.
In FIG. 10, filtered liquid stream 344 and hydrogen source 246 enter
hydrotreating unit 350. In some
embodiments, hydrogen source 246 may be added to filtered liquid stream 344
before entering hydrotreating unit
350. In some embodiments, sufficient hydrogen is present in liquid stream 334
and hydrogen source 246 is not
needed. In hydrotreating unit 350, contact of filtered liquid stream 344 with
hydrogen source 246 in the presence of
one or more catalysts produces liquid stream 352. Hydrotreating unit 350 may
be operated such that all or at least a
47
CA 02871784 2014-11-18
portion of liquid stream 352 is changed sufficiently to remove compositions
and/or inhibit formation of compositions
that may clog equipment positioned downstream of the hydrotreating unit 350.
The catalyst used in hydrotreating
unit 350 may be a commercially available catalyst. In some embodiments,
hydrotreating of liquid stream 334 is not
necessary.
In some embodiments, liquid stream 334 is contacted with hydrogen in the
presence of one or more
catalysts to change one or more desired properties of the crude feed to meet
transportation and/or refinery
specifications. Methods to change one or more desired properties of the crude
feed are described in U.S. Published
Patent Applications Nos. 20050133414 to Bhan et al.; 20050133405 to Wellington
et al.; and U.S. Patent
Application Serial Nos. 11/400,542 entitled "Systems, Methods, and Catalysts
for Producing a Crude Product" filed
April 7, 2006; 11/425,979 to Bhan entitled "Systems, Methods, and Catalysts
for Producing a Crude Product" filed
June 6, 2006: and 11/425,992 to Wellington et al., entitled "Systems, Methods,
and Catalysts for Producing a Crude
Product" filed June 6, 2006, all of which are incorporated by reference
herein.
In some embodiments, hydrotreating unit 350 is a selective hydrogenation unit.
In hydrotreating unit 350,
liquid stream 334 and/or filtered liquid stream 344 are selectively
hydrogenated such that di-olefins are reduced to
mono-olefins. For example, liquid stream 334 and/or filtered liquid stream 344
is contacted with hydrogen in the
presence of a DN-200 (Criterion Catalysts & Technologies, Houston Texas,
U.S.A.) at temperatures ranging from
100 C to 200 C and total pressures of 0.1 MPa to 40 MPa to produce liquid
stream 352. Liquid stream 352
includes a reduced content of di-olefins and an increased content of mono-
olefins relative to the di-olefin and mono-
olefin content of liquid stream 334. The conversion of di-olefins to mono-
olefins under these conditions is, in some
embodiments, at least 50%, at least 60%, at least 80% or at least 90%. Liquid
stream 352 exits hydrotreating unit
350 and enters one or more processing units positioned downstream of
hydrotreating unit 350. The units positioned
downstream of hydrotreating unit 350 may include distillation units, catalytic
reforming units, hydrocracking units,
hydrotreating units, hydrogenation units, hydrodesulfurization units,
catalytic cracking units, delayed coking units,
gasification units, or combinations thereof.
Liquid stream 352 may exit hydrotreating unit 350 and enter fractionation unit
354. Fractionation unit 354
produces one or more crude products. Fractionation may include, but is not
limited to, an atmospheric distillation
process and/or a vacuum distillation process. Crude products include, but are
not limited to, C3-05 hydrocarbon
stream 356, naphtha stream 358, kerosene stream 360, diesel stream 362, and
bottoms stream 364. Bottoms stream
364 generally includes hydrocarbons having a boiling range distribution of at
least 340 C at 0.101 MPa. In some
embodiments, bottoms stream 364 is vacuum gas oil. In other embodiments,
bottoms stream 364 includes
hydrocarbons with a boiling range distribution of at least 537 C. One or more
of the crude products may be sold
and/or further processed to gasoline or other commercial products.
To enhance the use of the streams produced from formation fluid, hydrocarbons
produced during
fractionation of the liquid stream and hydrocarbon gases produced during
separating the process gas may be
combined to form hydrocarbons having a higher carbon number. The produced
hydrocarbon gas stream may include
a level of olefins acceptable for alkylation reactions.
In some embodiments, hydrotreated liquid streams and/or streams produced from
fractions (for example,
distillates and/or naphtha) are blended with the in situ heat treatment
process liquid and/or formation fluid to produce
a blended fluid. The blended fluid may have enhanced physical stability and
chemical stability as compared to the
formation fluid. The blended fluid may have a reduced amount of reactive
species (for example, di-olefins, other
olefins and/or compounds containing oxygen, sulfur and/or nitrogen) relative
to the formation fluid. Thus, chemical
stability of the blended fluid is enhanced. The blended fluid may decrease an
amount of asphaltenes relative to the
48
CA 02871784 2014-11-18
formation fluid. Thus, physical stability of the blended fluid is enhanced.
The blended fluid may be a more a
fungible feed than the formation fluid and/or the liquid stream produced from
an in situ heat treatment process. The
blended feed may be more suitable for transportation, for use in chemical
processing units ancUor for use in refining
units than formation fluid.
In some embodiments, a fluid produced by methods described herein from an oil
shale formation may be
blended with heavy oil/tar sands in situ heat treatment process (IHTP) fluid.
Since the oil shale liquid is
substantially paraffinic and the heavy oil/tar sands IHTP fluid is
substantially aromatic, the blended fluid exhibits
enhanced stability. In certain embodiments, in situ heat treatment process
fluid may be blended with bitumen to
obtain a feed suitable for use in refining units. Blending of the IHTP fluid
and/or bitumen with the produced fluid
may enhance the chemical and/or physical stability of the blended product.
Thus, the blend may be transported
and/or distributed to processing units.
C3-05 hydrocarbon stream 356 produced from fractionation unit 354 and
hydrocarbon gas stream 330 enter
alkylation unit 368. In alkylation unit 368, reaction of the olefins in
hydrocarbon gas stream 330 (for example,
propylene, butylenes, amylenes, or combinations thereof) with the iso-
paraffins in C3-05 hydrocarbon stream 356
produces hydrocarbon stream 370. In some embodiments, the olefin content in
hydrocarbon gas stream 330 is
acceptable and an additional source of olefins is not needed. Hydrocarbon
stream 370 includes hydrocarbons having
a carbon number of at least 4. Hydrocarbons having a carbon number of at least
4 include, but are not limited to,
butanes, pentanes, hexanes, heptanes, and octanes. In certain embodiments,
hydrocarbons produced from alkylation
unit 368 have an octane number greater than 70, greater than 80, or greater
than 90. In some embodiments,
hydrocarbon stream 370 is suitable for use as gasoline without further
processing.
In some embodiments, bottoms stream 364 may be hydrocracked to produce naphtha
and/or other products.
The resulting naphtha may, however, need reformation to alter the octane level
so that the product may be sold
commercially as gasoline. Alternatively, bottoms stream 364 may be treated in
a catalytic cracker to produce
naphtha and/or feed for an alkylation unit. In some embodiments, naphtha
stream 358, kerosene stream 360, and
diesel stream 362 have an imbalance of paraffinic hydrocarbons, olefinic
hydrocarbons, and/or aromatic
hydrocarbons. The streams may not have a suitable quantity of olefins and/or
aromatics for use in commercial
products. This imbalance may be changed by combining at least a portion of the
streams to form combined stream
366 which has a boiling range distribution from about 38 C to about 343 C.
Catalytically cracking combined
stream 366 may produce olefins and/or other streams suitable for use in an
alkylation unit and/or other processing
units. In some embodiments, naphtha stream 358 is hydrocracked to produce
olefins.
In FIG. 10, combined stream 366 and bottoms stream 364 from fractionation unit
354 enters catalytic
cracking unit 372. Under controlled cracking conditions (for example,
controlled temperatures and pressures),
catalytic cracking unit 372 produces additional C3-05 hydrocarbon stream 356',
gasoline hydrocarbons stream 374,
and additional kerosene stream 360'.
Additional C3-05 hydrocarbon stream 356' may be sent to alkylation unit 368,
combined with C3-05
hydrocarbon stream 356, and/or combined with hydrocarbon gas stream 330 to
produce gasoline suitable for
commercial sale. In some embodiments, the olefin content in hydrocarbon gas
stream 330 is acceptable and an
additional source of olefins is not needed.
In some embodiments, an amount of the produced bottoms stream (for example,
VGO) is too low to sustain
operation of a hydrocracking unit or catalytic cracking unit and the
concentration of olefins in the produced gas
streams from a fractionation unit and/or a catalytic cracking unit (for
example, from fractionation unit 354 and/or
from catalytic cracking unit 372 in FIG. 10) may be too low to sustain
operation of an alkylation unit. The naphtha
49
CA 02871784 2014-11-18
produced from the fractionation unit may be treated to produce olefins for
further processing in, for example, an
alkylation unit. Reformulated gasoline produced by conventional naphtha
reforming processes may not meet
commercial specifications such as, for example, California Air Resources Board
mandates when liquid stream produced
from an in situ heat treatment process liquid is used as a feed stream. An
amount of olefins in the naphtha may be
saturated during conventional hydrotreating prior to the reforming naphtha
process. Thus, reforming of all the
hydrotreated naphtha may result in a higher than desired aromatics content in
the gasoline pool for reformulated gasoline.
The imbalance in the olefin and aromatic content in the reformed naphtha may
be changed by producing sufficient
alkylate from an alkylation unit to produce reformulated gasoline. Olefins
(for example, propylene and butylenes)
generated from fractionation and/or cracking of the naphtha may be combined
with isobutane to produce gasoline. In
addition, it has been found that catalytically cracking the naphtha and/or
other fractionated streams produced in a
fractionating unit requires additional heat because of a reduced amount of
coke production relative to other feedstocks
used in catalytic cracking units.
FIG. 11 depicts a schematic for treating liquid streams produced from an in
situ heat treatment process
stream to produce olefins and/or liquid streams. Similar processes to produce
middle distillate and olefins are
described in International Publication No. WO 2006/020547 and U.S. Patent
Application Publication Nos.
20060191820 and 20060178546 to Mo et al., all of which are incorporated by
referenced herein. Liquid stream 376
enters catalytic cracking system 378. Liquid stream 376 may include, but is
not limited to, liquid stream 334,
hydrotreated liquid stream 352, filtered liquid stream 344, naphtha stream
358, kerosene stream 360, diesel stream
362, and bottoms stream 364 from the system depicted in FIG. 10, any
hydrocarbon stream having a boiling range
distribution between 65 C and 800 C, or mixtures thereof. In some
embodiments, steam 272 enters catalytic
cracking system 378 and may atomize and/or lift liquid stream 376 to enhance
contact of the liquid stream with the
catalytic cracking catalyst. A ratio of steam to atomize liquid stream 376 to
feedstock may range from 0.01 to 2 by
weight, or from 0.1 to 1 by weight.
In catalytic cracking system 378, liquid stream 376 is contacted with a
catalytic cracking catalyst to produce
one or more crude products. The catalytic cracking catalyst includes a
selected catalytic cracking catalyst, at least a
portion of used regenerated cracking catalyst stream 380, at least a portion
of a regenerated cracking catalyst stream
382, or a mixture thereof. Used regenerated cracking catalyst 380 includes a
regenerated cracking catalyst that has
been used in second catalytic cracking system 384. Second catalytic cracking
system 384 may be used to crack
hydrocarbons to produce olefins and/or other crude products. Hydrocarbons
provided to second catalytic cracking
system 384 may include C3-05 hydrocarbons produced from the production wells,
gasoline hydrocarbons, hydrowax,
hydrocarbons produced from Fischer-Tropsch processes, biofuels, or
combinations thereof. The use of a mixture of
different types of hydrocarbon feed to the second catalytic cracking system
may enhance C3-05 olefin production to
meet the alkylate demand. Thus, integration of the products with refinery
processes may be enhanced. Second
catalytic cracking system 384 may be a dense phase unit, a fixed fluidized bed
unit, a riser, a combination of the
above mentioned units, or any unit or configuration of units known in the art
for cracking hydrocarbons.
Contact of the catalytic cracking catalyst and the liquid stream 376 in
catalytic cracking system 378
produces a crude product and spent cracking catalyst. The crude product may
include, but is not limited to,
hydrocarbons having a boiling point distribution that is less than the boiling
point distribution of liquid stream 376, a
portion of liquid stream 376, or mixtures thereof. The crude product and spent
catalyst enters separation system 386.
Separation system 386 may include, for example, a distillation unit, a
stripper, a filtration system, a centrifuge, or
any device known in the art capable of separating the crude product from the
spent catalyst.
CA 02871784 2014-11-18
Separated spent cracking catalyst stream 388 exits separation system 386 and
enters regeneration unit 390.
In regeneration unit 390, spent cracking catalyst is contacted with oxygen
source 392 (for example, oxygen and/or
air) under carbon burning conditions to produce regenerated cracking catalyst
stream 382 and combustion gases 394.
Combustion gases may form as a by-product of the removal of carbon and/or
other impurities formed on the catalyst
during the catalytic cracking process.
The temperature in regeneration unit 390 may range from about 621 C to about
760 C or from about 677
C to about 715 C. The pressure in regeneration unit 390 may range from
atmospheric to about 0.345 MPa or from
about 0.034 to about 0.345 MPa. The residence time of the separated spent
cracking catalyst in regeneration unit
390 ranges from about 1 to about 6 minutes or from or about 2 to about 4
minutes. The coke content on the
regenerated cracking catalyst is less than the coke content on the separated
spent cracking catalyst. Such coke
content is less than 0.5% by weight, with the weight percent being based on
the weight of the regenerated cracking
catalyst excluding the weight of the coke content. The coke content of the
regenerated cracking catalyst may range
from 0.01% by weight to 0.5% by weight, 0.05% by weight to 0.3% by weight, or
0.1% by weight to 0.2% by
weight.
In some embodiments, regenerated cracking catalyst stream 382 may be divided
into two streams with at
least a portion of regenerated cracking catalyst stream 382' exiting
regeneration unit 390 and entering second
catalytic cracking system 384. At least another portion of regenerated
cracking catalyst stream 382 exits regenerator
390 and enters catalytic cracking system 378. The relative amount of the used
regenerated cracking catalyst to the
regenerated cracking catalyst is adjusted to provide for the desired cracking
conditions within catalytic cracking
system 378. Adjusting the ratio of used regenerated cracking catalyst to
regenerated cracking catalyst may assist in
the control of the cracking conditions in catalytic cracking system 378. A
weight ratio of the used regenerated
cracking catalyst to the regenerated cracking catalyst may range from 0.1:1 to
100:1, from 0.5:1 to 20:1, or from 1:1
to 10:1. For a system operated at steady state, the weight ratio of used
regenerated cracking catalyst-to-regenerated
cracking catalyst approximates the weight ratio of the at least a portion of
regenerated cracking catalyst passing to
the second catalytic cracking system 384 to the remaining portion of
regenerated cracking catalyst that is mixed with
liquid stream 376 introduced into catalytic cracking system 378, and, thus,
the aforementioned ranges are also
applicable to such weight ratio.
Crude product 396 exits separation system 386 and enters liquid separation
unit 398. Liquid separation unit
398 may be any system known to those skilled in the art for recovering and
separating the crude product into product
streams such as, for example, gas stream 336', gasoline hydrocarbons stream
400, cycle oil stream 402, and bottom
stream 404. In some embodiments, bottom stream 404 is recycled to catalytic
cracking system 378. Liquid
separation unit 398 may include components and/or units such as, for example,
absorbers and strippers, fractionators,
compressors and separators, or any combination of known systems for providing
recovery and separation of products
from the crude product. In some embodiments, at least a portion of light cycle
oil stream 402 exits liquid separation
unit 398 and enters second catalytic cracking system 378. In some embodiments,
none of the light cycle oil stream is
sent to the second catalytic cracking system. In some embodiments, at least a
portion of gasoline hydrocarbons
stream 400 exits liquid separation unit 398 and enters second catalytic
cracking system 384. In some embodiments,
none of the gasoline hydrocarbons stream is sent to the second catalytic
cracking system. In some embodiments,
gasoline hydrocarbons stream 400 is suitable for sale and/or for use in other
processes.
At least a portion of gas oil hydrocarbon stream 406 (for example, vacuum gas
oil) and/or portions of
gasoline hydrocarbons stream 400 and at least a portion of light cycle oil
stream 402 are sent to catalytic cracking
system 384. The steams are catalytically cracked in the presence of steam 272'
to produce crude olefin stream 408.
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Crude olefin stream 408 may include hydrocarbons having a carbon number of at
least 2. In some embodiments,
crude olefin stream 408 contains at least 30% by weight C2-05 olefins, at
least 40% by weight C2-05 olefins, at least
50% by weight C2-05 olefins, at least 70% by weight C2-05 olefins, or at least
90% by weight C2-05 olefins. The
recycling of the gasoline hydrocarbons stream 400 into second catalytic
cracking system 384 may provide for an
additional conversion across the overall process system of gas oil hydrocarbon
stream 406 to C2-05 olefins.
In some embodiments, second catalytic cracking system 384 includes an
intermediate reaction zone and a
stripping zone that are in fluid communication with each other with the
stripping zone located below the
intermediate reaction zone. To provide for a high steam velocity within the
stripping zone, as compared to its
velocity within the intermediate reaction zone, the cross sectional area of
the stripping zone is less than the cross
sectional area of the intermediate reaction zone. The ratio of the stripping
zone cross sectional area to the
intermediate reaction zone cross sectional area may range from 0.1:1 to 0.9:1;
from 0.2:1 to 0.8:1; or from 0.3:1 to
0.7:1.
In some embodiments, the geometry of the second catalytic cracking system is
such that it is generally
cylindrical in shape. The length-to-diameter ratio of the stripping zone of
the catalystic cracking system is such as to
provide for the desired high steam velocity within the stripping zone and to
provide enough contact time within the
stripping zone for the desired stripping of the used regenerated catalyst that
is to be removed from the second
catalytic cracking system. Thus, the length-to-diameter dimension of the
stripping zone may range of from 1:1 to
25:1; from 2:1 to 15:1; or from 3:1 to 10:1.
In some embodiments, second catalytic cracking system 384 is operated or
controlled independently from
the operation or control of the catalytic cracking system 378. This
independent operation or control of second
catalytic cracking system 384 may improve overall conversion of the gasoline
hydrocarbons into the desired
products such as ethylene, propylene and butylenes. With the independent
operation of second catalytic cracking
system 384, the severity of catalytic cracking unit 378 may be reduced to
optimize the yield of C2-05 olefins. A
temperature in second catalytic cracking system 384 may range from about 482
C (900 F) to about 871 C (1600
F), from about 510 C. (950 F) to about 871 C (1600 F), or from about 538
C (1000 F) to about 732 C (1350
F). The operating pressure of second catalytic cracking system 384 may range
from atmospheric to about 0.345
MPa (50 psig) or from about 0.034 to 0.345 MPa (5 to 50 psig).
Addition of steam 272' into second catalytic cracking system 384 may assist in
the operational control of
the second catalytic cracking unit. In some embodiments, steam is not
necessary. In some embodiments, the use of
the steam for a given gasoline hydrocarbon conversion across the process
system, and in the cracking of the gasoline
hydrocarbons, may provide for an improved selectivity toward C2-05 olefin
yield with an increase in propylene and
butylenes yield relative to other catalytic cracking processes. A weight ratio
of steam to gasoline hydrocarbons
introduced into second catalytic cracking system 384 may be in the range of
upwardly to or about 15:1; from 0.1:1 to
10:1; from 0.2:1 to 9:1; or from 0.5:1 to 8:1.
Crude olefin stream 408 enters olefin separation system 410. Olefin separation
system 410 can be any
system known to those skilled in the art for recovering and separating the
crude olefin stream 408 into C2-05 olefin
product streams (for example, ethylene product stream 412, propylene product
stream 414, and butylenes products
stream 416). Olefin separation system 410 may include such systems as
absorbers and strippers, fractionators,
compressors and separators, or any combination of known systems or equipment
providing for the recovery and
separation of C2-05 olefin products from fluid stream 408. In some
embodiments, olefin streams 412, 414, 416 enter
alkylation unit 368 to generate hydrocarbon stream 370. In some embodiments,
hydrocarbon stream 370 has an
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octane number of at least 70, at least 80, or at least 90. In some
embodiments, all or portions of one or more of
streams 412, 414, 416 are transported to other processing units, such as
polymerization units, for use as feedstocks.
In some embodiments, the crude product from the catalytic cracking system and
the crude olefin stream
from second catalytic cracking system may be combined. The combined stream may
enter a single separation unit
(for example, a combination of liquid separation system 398 and olefin
separation system 410).
In FIG. 11, used cracking catalyst stream 380 exits second catalytic cracking
system 384 and enters
catalytic cracking system 378. Catalyst in used cracking catalyst stream 380
may include a slightly higher
concentration of carbon than the concentration of carbon that is on the
catalyst in regenerated cracking catalyst 382.
A high concentration of carbon on the catalyst may partially deactivate the
catalytic cracking catalysts which
provides for an enhanced yield of olefins from the catalytic cracking system
378. Coke content of the used
regenerated catalyst may be at least 0.1% by weight or at least 0.5% by
weight. The coke content of the used
regenerated catalyst may range from about 0.1% by weight to about 1% by weight
or from about 0.1% by weight to
about 0.6% by weight.
The catalytic cracking catalyst used in catalytic cracking system 378 and
second catalytic cracking system
384 may be any fluidizable cracking catalyst known in the art. The fluidizable
cracking catalyst may include a
molecular sieve having cracking activity dispersed in a porous, inorganic
refractory oxide matrix or binder.
"Molecular sieve" refers to any material capable of separating atoms or
molecules based on their respective
dimensions. Molecular sieves suitable for use as a component of the cracking
catalyst include pillared clays,
delaminated clays, and crystalline aluminosilicates. In some embodiments, the
cracking catalyst contains a
crystalline aluminosilicate. Examples of such aluminosilicates include Y
zeolites, ultrastable Y zeolites, X zeolites,
zeolite beta, zeolite L, offretite, mordenite, faujasite, and zeolite omega.
In some embodiments, crystalline
aluminosilicates for use in the cracking catalyst are X and/or Y zeolites.
U.S. Patent No. 3,130,007 to Breck
describes Y-type zeolites.
The stability and/or acidity of a zeolite used as a component of the cracking
catalyst may be increased by
exchanging the zeolite with hydrogen ions, ammonium ions, polyvalent metal
cations, such as rare earth-containing
cations, magnesium cations or calcium cations, or a combination of hydrogen
ions, ammonium ions and polyvalent
metal cations. The sodium content may be lowered until it is at most 0.8% by
weight, at most 0.5% by weight and at
most 0.3% by weight, calculated as Na20. Methods of carrying out the ion
exchange are well known in the art.
The zeolite or other molecular sieve component of the cracking catalyst is
combined with a porous,
inorganic refractory oxide matrix, or binder to form a finished catalyst prior
to use. The refractory oxide component
in the finished catalyst may be silica-alumina, silica, alumina, natural or
synthetic clays, pillared or delaminated
clays, mixtures of one or more of these components, and the like. In some
embodiments, the inorganic refractory
oxide matrix includes a mixture of silica-alumina and a clay such as kaolin,
hectorite, sepiolite, and attapulgite. A
finished catalyst may contain between about 5% by weight and about 40% by
weight zeolite or other molecular sieve
and greater than about 20 weight percent inorganic refractory oxide. In some
embodiments, the finished catalyst may
contain between about 10% and about 35% by weight zeolite or other molecular
sieve, between about 10% and
about 30% by weight inorganic refractory oxide, and between about 30% and
about 70% by weight clay.
The crystalline aluminosilicate or other molecular sieve component of the
cracking catalyst may be
combined with the porous, inorganic refractory oxide component or a precursor
thereof by any suitable technique
known in the art including mixing, mulling, blending or homogenization.
Examples of precursors that may be used
include, but are not limited to, alumina, alumina sols, silica sols, zirconia,
alumina hydrogels, polyoxycations of
aluminum and zirconium, and peptized alumina. In some embodiments, the zeolite
is combined with an alumino-
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silicate gel or sol or other inorganic, refractory oxide component, and the
resultant mixture is spray dried to produce
finished catalyst particles normally ranging in diameter between about 40
micrometers and about 80 micrometers. In
some embodiments, the zeolite or other molecular sieve may be mulled or
otherwise mixed with the refractory oxide
component or precursor thereof, extruded and then ground into the desired
particle size range. The finished catalyst
may have an average bulk density between about 0.30 and about 0.90 gram per
cubic centimeter and a pore volume
between about 0.10 and about 0.90 cubic centimeter per gram.
In some embodiments, a ZSM-5 additive may be introduced into the intermediate
cracking reactor of
second catalytic cracking system 384. When a ZSM-5 additive is used along with
the selected cracking catalyst in
the intermediate cracking reactor, a yield of the lower olefins such as
propylene and butylenes is enhanced. An
amount of ZSM-5 ranges from at most 30% by weight, at most 20% by weight, or
at most 18% by weight of the
regenerated catalyst being introduced into second catalytic cracking system
384. An amount of ZSM-5 additive is
introduced into second catalytic cracking system 384 may range from 1% to 30%
by weight, 3% to 20% by weight,
or 5% to 18% by weight of the regenerated cracking catalyst being introduced
into second catalytic cracking system
384.
The ZSM-5 additive is a molecular sieve additive selected from the family of
medium pore size crystalline
aluminosilicates or zeolites. Molecular sieves that can be used as the ZSM-5
additive include, but are not limited to,
medium pore zeolites as described in "Atlas of Zeolite Structure Types," Eds.
W. H. Meier and D. H. Olson,
Butterworth-Heineman, Third Edition, 1992. The medium pore size zeolites
generally have a pore size from about
0.5 nm, to about 0.7 nm and include, for example, MF1, MFS, MEL, MTW, EUO,
MTT, HEU, FER, and TON
structure type zeolites (IUPAC Commission of Zeolite Nomenclature). Non-
limiting examples of such medium pore
size zeolites, include ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-34, ZSM-35, ZSM-38,
ZSM-48, ZSM-50, silicalite,
and silicalite 2. ZSM-5, are described in U.S. Pat. Nos. 3,702,886 to Argauer
et al. and 3,770,614 to Graven, both of
which are incorporated by reference herein.
ZSM-1I is described in U.S. Patent No. 3,709,979 to Chu; ZSM-12 in U.S. Patent
No. 3,832,449 to
Rosinski et al.; ZSM-21 and ZSM-38 in U.S. Patent No. 3,948,758 to Bonacci et
al.; ZSM-23 in U.S. Patent No.
4,076,842 to Plank et al.; and ZSM-35 in U.S. Patent No. 4,016,245 to Plank et
al., all of which are incorporated by
reference herein. Other suitable molecular sieves include the
silicoaluminophosphates (SAPO), such as SAPO-4 and
SAP0-11 which is described in U.S. Patent No. 4,440,871 to Lok etal.;
chromosilicates; gallium silicates, iron
silicates; aluminum phosphates (ALPO), such as ALPO-11 described in U.S.
Patent No. 4,310,440 to Wilson et al.;
titanium aluminosilicates (TASO), such as TASO-45 described in U.S. Patent No.
4,686,029 to Pellet et al.; boron
silicates, described in U.S. Patent No. 4,254,297 Frenken et al.; titanium
aluminophosphates (TAPO), such as
TAPO-11 described in U.S. Patent No. 4,500,651 to Lok et al.; and iron
aluminosilicates, all of which are
incorporated by reference herein.
U.S. Patent No. 4,368,114 to Chester et al., which is incorporated by
reference herein, describes in detail
the class of zeolites that can be suitable ZSM-5 additives. The ZSM-5 additive
may be held together with a
catalytically inactive inorganic oxide matrix component, in accordance with
conventional methods.
In some embodiments, residue produced from units described in FIGS. 10 and 11
may be used as an energy
source. The residue may be gasified to produce gases which are burned (for
example, burned in a turbine) and/or
injected into a subsurface formation (for example, injection of produced
carbon dioxide into a subsurface formation).
In certain embodiments, the residue is de-asphalted to produce asphalt. The
asphalt may be gasified.
During some in situ heat treatment processes, ammonia may be in formation
fluid produced from the
formation. Produced ammonia may be used for a number of purposes. In some
embodiments, the ammonia or a
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portion of the ammonia may be used to produce hydrogen. In some embodiments,
the Haber-Bosch process may be
used to produce hydrogen. Ammonia may produce hydrogen and nitrogen according
to the following equilibrium
reaction:
(1) N, + 3 H24-, 2NH3
The reaction may be a high temperature, high pressure, catalyzed reaction. The
temperature may be from
about 300 C to about 800 C. The pressure may be from about 80 bars to about
220 bars. The catalyst may be
composed substantially of iron. The total amount of hydrogen produced may be
increased by shifting the
equilibrium towards hydrogen and nitrogen production. Equilibrium may be
shifted to produce more nitrogen and
hydrogen by removing nitrogen and/or hydrogen as they are produced.
Many wells are needed for treating a hydrocarbon formation using an in situ
heat treatment process. In
some embodiments, vertical or substantially vertical wells are formed in the
formation. In some embodiments,
horizontal or U-shaped wells are formed in the formation. In some embodiments,
combinations of horizontal and
vertical wells are formed in the formation. Wells may be formed using drilling
rigs.
In an embodiment, a rig for drilling wells includes equipment on the rig for
drilling multiple wellbores
simultaneously. The rig may include one or more systems for constructing the
wells, including drilling, fluid
handling, and cementing of the wells through the overburden, drilling to total
depth, and placing completion
equipment such as heaters and casing. The rig may be particularly useful for
forming closely spaced wells, such as
freeze wells.
In some embodiments, a rig for drilling wellbores for an in situ heat
treatment process may be a movable
platform. The working surface of the platform may be 20 m or more above the
ground. Piping may be suspended
from the bottom of the platform before being deployed.
In some embodiments, wells are drilled in sequential stages with different
drilling machines. The wells
may be barrier wells, heater wells, production wells, production/heater wells,
monitor wells, injection wells, or other
types of wells. A conductor drilling machine may set the conductor of the
well. A main hole drilling machine may
drill the wellbore to depth. A completion drilling machine may place casing,
cement, tubing, cables, heaters, and
perform other well completion tasks. The drilling machines may be on the same
location moving 3 to 10 meters
between wells for 2 to 3 years. The size and the shape of the drilling
machines may not have to meet existing road
transportation regulations since once in the field, the drilling machines may
remain there for the duration of the
project. The major components of the drilling machines may be transported to
location and assembled there. The
drilling machines may not have to be disassembled for a multi-mile move for
several years.
One or more central plants may support the drilling machines. The use of a
central plant may allow for
smaller drilling machines. The central plant may include prime movers, mud
tanks, solids handling equipment, pipe
handling, power, and other equipment common to the drilling machines. The
equipment of the central plant may be
coupled to the drilling machines by flexible umbilicals, by easily modifiable
piping, and/or by quick release
electrical connections. Several wells may be drilled before the need to move
the central plant arises. In some
embodiments, the central plant may be moved while connected to one or more
operating drilling machines. The
drilling machines and central plant may be designed with integrated drip pans
to capture leaks and spills.
In some embodiments, the drilling machines are powered directly off the
electric grid. In other
embodiments, the drilling machines are diesel powered. Using diesel power may
avoid complications associated
with interfering with the installation of electrical and other systems needed
for the wells of the in situ heat treatment
process.
CA 02871784 2014-11-18
The drilling machines may be automated so that little or no human interaction
is required. The tubulars
used by the drilling machines may be stacked and stored on or by the drilling
machines so that the drilling machines
can access and manipulate the tubulars with minimal or no human intervention.
For example, a carousel or other
device may be used to store a tubular and move the tubular from storage to the
drilling mast. The carousel or other
device may also be used to move the tubular from the drilling mast to storage.
The drilling machines may include propulsion units so that the drilling
machines do not need to be skidded.
The central plant may also include propulsion units. Skidding involves extra
equipment not used for drilling the
wells and may be complicated by the dense concentration of surface facilities
and equipment. In some
embodiments, the drilling machines and/or central plant may include tracks or
a walking mechanism to eliminate
railroad-type tracks. Eliminating railroad-type tracks may reduce the amount
of pre-work road and rail formation
that needs to be completed before drilling operations can begin. In some
embodiments, the propulsion units may
include a fixed-movement mechanism. The fixed-movement mechanism may advance
the drilling machine a set
distance when activated so that the drilling machine is located at the next
well location. Fine adjustment may allow
for exact positioning of the drilling machine after initial position location
by the fixed-movement mechanism. In
some embodiments, laser guidance systems may be utilized to position the
drilling machines. The laser guidance
systems may ensure that the wellbores being formed are started at the right
location in the well pattern. In some
embodiments, drilling machines and/or the central plant are positioned on a
central track or access lane. The drilling
equipment may be extended from one side to the other of the central track to
form the wells. The drilling machine is
able to stay in one place while an arm or cantilever mechanism allows
multiples of wells to be drilled around the
drilling machine. The wells may be drilled in very close proximity if
required.
The drilling machines and the central plant may be self-leveling and able to
function on up to a 10% grade
or higher. In some embodiments, the drilling machines include hydraulic and/or
mechanical leveling systems. The
drilling machines and central plant may have ground clearances of at least I
meter so that the units may be moved
unobstructed over wellheads. Each drilling machine may include a mechanism for
precisely placing the working
components of the drilling machine over the hole center of the well being
formed. In some embodiments, the
mechanism adjusts the position of a derrick of the drilling machine.
The drilling machines may be moved from one well to another with derricks of
the drilling machines in
upright or inclined positions. The term "derrick" is used to represent
whatever top drive support device is employed
on the rig, whether the top drive support device is a derrick, stiff mast, or
hydraulic arm. Because some drilling
machines may use three 10 m pipe sections, the derrick may have to be lowered
for rig moves. If the derrick must be
lowered, lowering and raising the derrick needs to be a quick and safe
operation. In some embodiments, the derrick
is lowered with the bottom hole assembly racked in the derrick to save time
handling the bottom hole assembly. In
other embodiments, the bottom hole assembly is separated from the derrick for
servicing during a move of the
drilling machine.
In some embodiments, one of the drilling machines is able to do more than one
stage of well formation. In
some embodiments, a freeze wall or other barrier is formed around all or a
portion of a treatment area. There may be
about a year or more of time from when the last freeze well is drilled to the
time that main holes for heater and
producer wells can be drilled. In the intervening time, the drilling machine
used to drill the main hole of a well may
be used to preset conductors for heater wells and/or production wells in the
treatment area.
In some embodiments, two or more drilling machines are placed on the same
carrier. For example, the
carrier may include equipment that presets the conductor for a well. The
carrier may also carry equipment for
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CA 02871784 2014-11-18
forming the main hole. One portion of the machine could be presetting a
conductor while another portion of the
machine could be simultaneously forming the main hole of a second well.
Running drill pipe to replace bits, running in down hole equipment and pulling
the equipment out after use
may be time consuming and expensive. To save time and expense, all drilling
and completion tools may go into the
hole and not come out. For example, drill pipe may become casing. Once data is
obtained from logging runs, the
logging tools are left in the hole and drilling proceeds through them or past
them if necessary. Downhole equipment
is integrated into the drill pipe. In some embodiments, the drill pipe becomes
a conduit of a conduit-in-conduit
heater.
In some embodiments, a retractable drilling assembly is used. Using a
retractable drilling assembly may be
beneficial when using continuous coiled tubing. When total depth of the well
is reached, the drill bit and bottom
hole assembly may be retracted to a smaller diameter. The drill bit and bottom
hole assembly may be brought to the
surface through the coiled tubing. The coiled tubing may be left in the hole
as casing.
In some embodiments, the main hole drilling machine and the completion
drilling machine include a quick-
connect device for attaching the fluid diverter spool (drilling wellhead) to
the conductor casing. The use of a quick-
connect device may be faster than threading or welding the diverter to the
conductor casing. The quick-connect
device may be a snap-on or clamp-on type diverter. Wellheads are typically
designed to fit a multitude of casing
configurations, everything from 48 inch conductor to 2-3/8 inch tubing. For an
in situ heat treatment process, the
wellheads may not need to span such a large casing diameter set or have
multiple string requirements. The
wellheads may only handle a very limited pipe diameter range and only one or
two casing strings. Having a fit for
purpose wellhead may significantly reduce the cost of fabricating and
installing the wellheads for the wells of the in
situ heat treatment process.
In some embodiments, the main hole drilling machine includes a slickline/boom
system. The
slickline/boom system may allow running ranging equipment in a close offset
well while drilling the well the drilling
machine is positioned over. The use of the slickline/boom system on the
drilling machine may eliminate the need for
additional equipment for employing the ranging equipment.
In some embodiments, the conductor drilling machine is a blast-hole rig. The
blast-hole rig may be
mounted on a crawler or carrier with metal tracks. Air or gas compression is
on board the blast-hole rig. Tubulars
= may be racked horizontally on the blast-hole rig. The derrick of the
blast-hole rig may be adjusted to hole center.
The bottom hole drilling assembly of the blast-hole rig may be left in the
derrick when the blast-hole rig is moved.
In some embodiments, the blast-hole rig includes an integral drilling fluid
tank, solids control equipment, and a mist
collector. In some embodiments, the drilling fluid tank, the solids control
equipment, and/or the mist collector is part
of the central plant.
During well formation with jointed pipe, one time consuming task is making
connections. To reduce the
number of connections needed during formation of wells, long lengths of pipe
may be used. In some embodiments,
the drilling machines are able to use pipe with a length of about 25 m to 30
m. The 25 m to 30 m piping may be
made up of two or more shorter joints, but is preferably a single joint of the
appropriate length. Using a single joint
may decrease the complexity of pipe handling and result in fewer potential
leak paths in the drill string. In some
embodiments, the drilling machines use jointed pipe having other lengths, such
as 20 m lengths, or 10 m lengths.
The drilling machine may use a top drive system. In some embodiments, the top
drive system functions
using a rack and pinion. In some embodiments, the top drive system functions
using a hydraulic system.
The drilling machines may include automated pipe handling systems. The
automated pipe handling system
may be able to lift pipe, make connections, and have another joint in the
raised position ready for the next
57
CA 02871784 2014-11-18
connection. The automated pipe handling systems may include an iron roughneck
to make and break connections.
In some embodiments, the pipe skid for the drilling machine is an integral
component of the drilling machine.
String floats (check valves) may be needed in the drill string because air
and/or liquid will be used during
drilling. An integral float valve may be positioned in each joint used by the
drilling machine. Including a string
float in each joint may minimize circulating times at connections and speed up
the connection process.
Drilling the wells may be done at low operating pressures. In some
embodiments, a quick-connect coupler
is used to connect drill pipe together because of the low operating pressures.
Using quick-connect couplers to join
drill pipe may reduce drilling time and simplify pipe handling automation.
In certain embodiments, the main hole drilling machine is designed to drill 6-
1/4 inch or 6-1/2 inch holes.
The pumping capabilities needed to support the main hole drilling machine may
include 3 x 900 scfm air
compressors, a 2000 psi booster, and a liquid pump with an operational maximum
of 325 gpm. A 35 gpm pump may
also be included if mist drilling is required.
In some embodiments, the main hole drilling machine and/or the completion
drilling machine uses coiled
tubing. Coiled tubing may allow for minimal or no pipe connections above the
bottom hole assembly. However, the
drilling machine still needs the ability to deploy and retrieve the individual
components of the bottom hole assembly.
= In some embodiments, components are automatically retrieved by a
carousel, deployed, and made up over the hole
when running in the hole. The process may be reversed when tripping out of the
hole. Alternatively, components
may be racked horizontally on the drilling machine. The components may be
maneuvered with automatic pipe arms.
The drilling machine may employ a split injector system. When coiled tubing
operations are halted, the two
sides of the injector may be remotely unlatched and retracted to allow for
over hole access.
In some embodiments that use coiled tubing, a bottom hole assembly handling
rig is used to make up and
deploy the bottom hole assembly in the well conductor of a well to be drilled
to total depth. The drilling machine
may leave the current bottom hole assembly in the well after reaching total
depth and prior to moving to the next
well. After latching on to the bottom hole assembly in the follow up well, the
bottom hole assembly handling rig
may pull the bottom hole assembly from the previous well and prepare it for
the next well in sequence. The mast for
the bottom hole assembly handling rig may be a very simple arrangement
supporting a sandline for bottom hole
assembly handling. In some embodiments, the wellbore in which the coiled
tubing is placed is formed by jet
drilling.
In some embodiments, coiled tubing may be carbon steel. Carbon steel coiled
tubing may be used for only
a limited number of cycles because coiling and/or uncoiling the steel forces
the coiled tubing past the elastic region
of the stress/strain curve and into the plastic region. In the plastic region,
the steel is permanently deformed and/or
weakened. For some coiled tubing uses, the coiled tubing is placed in the
formation and left in the formation, so the
use of carbon steel coiled tubing does not present a problem. For some coiled
tubing uses, the coiled tubing may be
coiled and uncoiled many times. For coiled tubing that needs to be coiled and
uncoiled many times, the coiled
tubing may be composite coiled tubing. Composite coiled tubing may stay in the
elastic region during coiling and
uncoiling so that there is little or no permanent deformation of the coiled
tubing during deployment and retrieval.
Composite coiled tubing is available from Fiberspar LinePipe LLC (Houston,
Texas, U.S.A.). In some
embodiments, composite coiled tubing may include one or more electrical wires
in the composite. The electrical
wires may be coupled to equipment and lowered into the wellbore with the
coiled tubing.
Coiled tubing may be stored on a reel before deployment. A reel used by the
drilling machine may have
500-1000 m of pipe. To increase the number of cycles the coiled tubing may be
used, the reel may have a large
58
CA 02871784 2014-11-18
diameter and be relatively narrow. In some embodiments, the coiled tubing reel
is the wellhead. Having the
wellhead and the reel as one unit eliminates the additional handling of a
separate wellhead and an empty reel.
Reverse circulation drilling enables fast penetration rates and the use of low
density drilling fluid such as air
or mist. When tri-cone rock bits are used, a skirted rock bit assembly
replaces the conventional tri-cone bit. The
skirt directs the drilling fluid from the pipe-in-pipe drill rod annulus to
the outside portion of the hole being drilled.
As the cuttings are generated by the action of the rotating drill bit, the
cuttings mix with the drilling fluid, pass
through a hole in the center of the bit and are carried out of the hole
through the center of the drill rods. When a
non-skirted drill bit is used, a reverse-circulation crossover is installed
between the standard bit and the drill rods.
The crossover redirects the drilling fluid from the pipe-in-pipe drill rod
annulus to the inside of the drill string about
a meter above the bit. The drilling fluid passes through the bit jets, mixes
with the cuttings, and returns up the drill
string. At the crossover, the fluid/cuttings mixture enters the drill string
and continues to the surface inside the inner
tube of the drill rod.
FIG. 12 depicts a schematic drawing of a reverse-circulating polycrystalline
diamond compact drill bit
design. The reverse-circulating polycrystalline diamond compact (RC-PDC) drill
bit design eliminates the
crossover. RC-PDC bit 418 may include skirt 420 that directs the drilling
fluid from pipe-in-pipe drill rod annulus
422 to bottom portion 424 of the wellbore being formed. In bottom portion 424,
the drilling fluid mixes with the
cuttings generated by cutters 426 of the RC-PDC bit. The drilling fluid and
cuttings pass through opening 428 in the
center of RC-PDC bit 418 and are carried out of the wellbore through drill rod
center 430.
In some embodiments, the cuttings generated during drilling are milled and
used as a filler material in a
slurry used for forming a grout wall. Cuttings that contain hydrocarbon
material may be retorted to extract the
hydrocarbons. Retorting the cuttings may be environmentally beneficial because
the reinjected cuttings are free of
organic material. Recovering the hydrocarbons may offset a portion of the
milling cost.
FIG. 13 depicts a schematic drawing of a drilling system. Pilot bit 432 may
form an opening in the
formation. Pilot bit 432 may be followed by final diameter bit 434. In some
embodiments, pilot bit 432 may be
about 2.5 cm in diameter. Pilot bit 432 may be one or more meters below final
diameter bit 434. Pilot bit 432 may
rotate in a first direction and final diameter bit 434 may rotate in the
opposite direction. Counter-rotating bits may
allow for the formation of the wellbore along a desired path. Standard mud may
be used in both pilot bit 432 and
final diameter bit 434. In some embodiments, air or mist may be used as the
drilling fluid in one or both bits.
During some in situ heat treatment processes, wellbores may need to be formed
in heated formations.
Wellbores drilled into hot formation may be additional or replacement heater
wells, additional or replacement
production wells and/or monitor wells. In some in situ heat treatment
processes, a barrier formed around all or a
portion of the in situ heat treatment process is formed by freeze wells that
form a low temperature zone around the
freeze wells. A portion of the cooling capacity of the freeze well equipment
may be utilized to cool the equipment
needed to drill into the hot formation. Drilling bits may be advanced slowly
in hot sections to ensure that the formed
wellbore cools sufficiently to preclude drilling problems.
FIG. 14 depicts a schematic drawing of a system for drilling into a hot
formation. Cold mud is introduced
to drilling bit 434 through conduit 436. As the bit penetrates into the
formation, the mud cools the bit and the
surrounding formation. In an embodiment, a pilot hole is formed first and the
wellbore is finished with a larger drill
bit later. In an embodiment, the finished wellbore is formed without a pilot
hole being formed. Well advancement is
very slow to ensure sufficient cooling.
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CA 02871784 2014-11-18
FIG. 15 depicts a schematic drawing of a system for drilling into a hot
formation. Mud is introduced
through conduit 436. Closed loop system 438 is used to circulate cooling
fluid. The cooling fluid cools the drilling
mud and the formation as drilling bit 434 slowly penetrates into the
formation.
FIG. 16 depicts a schematic drawing of a system for drilling into a hot
formation. Mud is introduced
through conduit 436. Pilot bit 432 is followed by final diameter bit 434.
Closed loop system 438 is used to circulate
cooling fluid. The cooling fluid cools the drilling mud supplied to the drill
bits. The cooled drilling mud cools the
formation.
In some embodiments, one or more portions of a wellbore may need to be
isolated from other portions of
the wellbore to establish zonal isolation. In some embodiments, an expandable
may be positioned in the wellbore
adjacent to a section of the wellbore that is to be isolated. A pig or
hydraulic pressure may be used to enlarge the
expandable to establish zonal isolation.
In some embodiments, pathways may be formed in the formation after the
wellbores are formed. Pathways
may be formed adjacent to heater wellbores and/or adjacent to production
wellbores. The pathways may promote
better fluid flow and/or better heat conduction. In some embodiments, pathways
are formed by hydraulically
fracturing the formation. Other fracturing techniques may also be used. In
some embodiments, small diameter bores
may be formed in the formation. In some embodiments, heating the formation may
expand and close or substantially
close the fractures or bores formed in the formation to enhance heat
conduction.
Some wellbores formed in the formation may be used to facilitate formation of
a perimeter barrier around a
treatment area. Heat sources in the treatment area may heat hydrocarbons in
the formation within the treatment area.
The perimeter barrier may be, but is not limited to, a low temperature or
frozen barrier formed by freeze wells,
dewatering wells, a grout wall formed in the formation, a sulfur cement
barrier, a barrier formed by a gel produced in
the formation, a barrier formed by precipitation of salts in the formation, a
barrier formed by a polymerization
reaction in the formation, and/or sheets driven into the formation. Heat
sources, production wells, injection wells,
dewatering wells, and/or monitoring wells may be installed in the treatment
area defined by the barrier prior to,
simultaneously with, or after installation of the barrier.
A low temperature zone around at least a portion of a treatment area may be
formed by freeze wells. In an
embodiment, refrigerant is circulated through freeze wells to form low
temperature zones around each freeze well.
The freeze wells are placed in the formation so that the low temperature zones
overlap and form a low temperature
zone around the treatment area. The low temperature zone established by freeze
wells is maintained below the
freezing temperature of aqueous fluid in the formation. Aqueous fluid entering
the low temperature zone freezes and
forms the frozen barrier. In other embodiments, the freeze barrier is formed
by batch operated freeze wells. A cold
fluid, such as liquid nitrogen, is introduced into the freeze wells to form
low temperature zones around the freeze
wells. The fluid is replenished as needed.
In some embodiments, two or more rows of freeze wells are located about all or
a portion of the perimeter
of the treatment area to form a thick interconnected low temperature zone.
Thick low temperature zones may be
formed adjacent to areas in the formation where there is a high flow rate of
aqueous fluid in the formation. The thick
barrier may ensure that breakthrough of the frozen barrier established by the
freeze wells does not occur.
In some embodiments, a double barrier system is used to isolate a treatment
area. The double barrier
system may be formed with a first barrier and a second barrier. The first
barrier may be formed around at least a
portion of the treatment area to inhibit fluid from entering or exiting the
treatment area. The second barrier may be
formed around at least a portion of the first barrier to isolate an inter-
barrier zone between the first barrier and the
CA 02871784 2014-11-18
second barrier. The inter-barrier zone may have a thickness from about 1 m to
about 300 m. In some embodiments,
the thickness of the inter-barrier zone is from about 10 m to about 100 m, or
from about 20 m to about 50 m.
The double barrier system may allow greater project depths than a single
barrier system. Greater depths are
possible with the double barrier system because the stepped differential
pressures across the first barrier and the
second barrier is less than the differential pressure across a single barrier.
The smaller differential pressures across
the first barrier and the second barrier make a breach of the double barrier
system less likely to occur at depth for the
double barrier system as compared to the single barrier system.
The double barrier system reduces the probability that a barrier breach will
affect the treatment area or the
formation on the outside of the double barrier. That is, the probability that
the location and/or time of occurrence of
the breach in the first barrier will coincide with the location and/or time of
occurrence of the breach in the second
barrier is low, especially if the distance between the first barrier and the
second barrier is relatively large (for
example, greater than about 15 m). Having a double barrier may reduce or
eliminate influx of fluid into the
treatment area following a breach of the first barrier or the second barrier.
The treatment area may not be affected if
the second barrier breaches. If the first barrier breaches, only a portion of
the fluid in the inter-barrier zone is able to
enter the contained zone. Also, fluid from the contained zone will not pass
the second barrier. Recovery from a
breach of a barrier of the double barrier system may require less time and
fewer resources than recovery from a
breach of a single barrier system. For example, reheating a treatment area
zone following a breach of a double
barrier system may require less energy than reheating a similarly sized
treatment area zone following a breach of a
single barrier system.
The first barrier and the second barrier may be the same type of barrier or
different types of barriers. In
some embodiments, the first barrier and the second barrier are formed by
freeze wells. In some embodiments, the
first barrier is formed by freeze wells, and the second barrier is a grout
wall. The grout wall may be formed of
cement, sulfur, sulfur cement, or combinations thereof. In some embodiments, a
portion of the first barrier and/or a
portion of the second barrier is a natural barrier, such as an impermeable
rock formation.
Vertically positioned freeze wells and/or horizontally positioned freeze wells
may be positioned around
sides of the treatment area. If the upper layer (the overburden) or the lower
layer (the underburden) of the formation
is likely to allow fluid flow into the treatment area or out of the treatment
area, horizontally positioned freeze wells
may be used to form an upper and/or a lower barrier for the treatment area. In
some embodiments, an upper barrier
and/or a lower barrier may not be necessary if the upper layer and/or the
lower layer are at least substantially
impermeable. If the upper freeze barrier is formed, portions of heat sources,
production wells, injection wells, and/or
dewatering wells that pass through the low temperature zone created by the
freeze wells forming the upper freeze
barrier wells may be insulated and/or heat traced so that the low temperature
zone does not adversely affect the
functioning of the heat sources, production wells, injection wells and/or
dewatering wells passing through the low
temperature zone.
Spacing between adjacent freeze wells may be a function of a number of
different factors. The factors may
include, but are not limited to, physical properties of formation material,
type of refrigeration system, coldness and
thermal properties of the refrigerant, flow rate of material into or out of
the treatment area, time for forming the low
temperature zone, and economic considerations. Consolidated or partially
consolidated formation material may
allow for a large separation distance between freeze wells. A separation
distance between freeze wells in
consolidated or partially consolidated formation material may be from about 3
m to about 20 m, about 4 m to about
15 m, or about 5 m to about 10 m. In an embodiment, the spacing between
adjacent freeze wells is about 5 m.
Spacing between freeze wells in unconsolidated or substantially unconsolidated
formation material, such as in tar
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CA 02871784 2014-11-18
sand, may need to be smaller than spacing in consolidated formation material.
A separation distance between freeze
wells in unconsolidated material may be from about I m to about 5 m.
Freeze wells may be placed in the formation so that there is minimal deviation
in orientation of one freeze
well relative to an adjacent freeze well. Excessive deviation may create a
large separation distance between adjacent
freeze wells that may not permit formation of an interconnected low
temperature zone between the adjacent freeze
wells. Factors that influence the manner in which freeze wells are inserted
into the ground include, but are not
limited to, freeze well insertion time, depth that the freeze wells are to be
inserted, formation properties, desired well
orientation, and economics.
Relatively low depth wellbores for freeze wells may be impacted and/or
vibrationally inserted into some
formations. Wellbores for freeze wells may be impacted and/or vibrationally
inserted into formations to depths from
about 1 m to about 100 m without excessive deviation in orientation of freeze
wells relative to adjacent freeze wells
in some types of formations.
Wellbores for freeze wells placed deep in the formation, or wellbores for
freeze wells placed in formations
with layers that are difficult to impact or vibrate a well through, may be
placed in the formation by directional
drilling and/or geosteering. Acoustic signals, electrical signals, magnetic
signals, and/or other signals produced in a
first wellbore may be used to guide directionally drilling of adjacent
wellbores so that desired spacing between
adjacent wells is maintained. Tight control of the spacing between wellbores
for freeze wells is an important factor
in minimizing the time for completion of barrier formation.
In some embodiments, one or more portions of freeze wells may be angled in the
formation. The freeze
wells may be angled in the formation adjacent to aquifers. In some
embodiments, the angled portions are angled
outwards from the treatment area. In some embodiments, the angled portions may
be angled inwards towards the
treatment area. The angled portions of the freeze wells allow extra length of
freeze well to be positioned in the
aquifer zones. Also, the angled portions of the freeze wells may reduce the
shear load applied to the frozen barrier
by water flowing in the aquifer.
After formation of the wellbore for the freeze well, the wellbore may be
backflushed with water adjacent to
the part of the formation that is to be reduced in temperature to form a
portion of the freeze barrier. The water may
displace drilling fluid remaining in the wellbore. The water may displace
indigenous gas in cavities adjacent to the
formation. In some embodiments, the wellbore is filled with water from a
conduit up to the level of the overburden.
In some embodiments, the wellbore is backflushed with water in sections. The
wellbore maybe treated in sections
having lengths of about 6 m, 10 m, 14 m, 17 m, or greater. Pressure of the
water in the wellbore is maintained below
the fracture pressure of the formation. In some embodiments, the water, or a
portion of the water is removed from
the wellbore, and a freeze well is placed in the formation.
FIG. 17 depicts an embodiment of freeze well 440. Freeze well 440 may include
canister 442, inlet conduit
444, spacers 446, and wellcap 448. Spacers 446 may position inlet conduit 444
in canister 442 so that an annular
space is formed between the canister and the conduit. Spacers 446 may promote
turbulent flow of refrigerant in the
annular space between inlet conduit 444 and canister 442, but the spacers may
also cause a significant fluid pressure
drop. Turbulent fluid flow in the annular space may be promoted by roughening
the inner surface of canister 442, by
roughening the outer surface of inlet conduit 444, and/or by having a small
cross-sectional area annular space that
allows for high refrigerant velocity in the annular space. In some
embodiments, spacers are not used. Wellhead 450
may suspend canister 442 in wellbore 452.
Formation refrigerant may flow through cold side conduit 454 from a
refrigeration unit to inlet conduit 444
of freeze well 440. The formation refrigerant may flow through an annular
space between inlet conduit 444 and
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CA 02871784 2014-11-18
canister 442 to warm side conduit 456. Heat may transfer from the formation to
canister 442 and from the canister to
the formation refrigerant in the annular space. Inlet conduit 444 may be
insulated to inhibit heat transfer to the
formation refrigerant during passage of the formation refrigerant into freeze
well 440. In an embodiment, inlet
conduit 444 is a high density polyethylene tube. At cold temperatures, some
polymers may exhibit a large amount of
thermal contraction. For example, a 260 m initial length of polyethylene
conduit subjected to a temperature of about
-25 C may contract by 6 m or more. If a high density polyethylene conduit, or
other polymer conduit, is used, the
large thermal contraction of the material must be taken into account in
determining the final depth of the freeze well.
For example, the freeze well may be drilled deeper than needed, and the
conduit may be allowed to shrink back
during use. In sonic embodiments, inlet conduit 444 is an insulated metal
tube. In some embodiments, the
insulation may be a polymer coating, such as, but not limited to,
polyvinylchloride, high density polyethylene, ancUor
polystyrene.
Freeze well 440 may be introduced into the formation using a coiled tubing
rig. In an embodiment, canister
442 and inlet conduit 444 are wound on a single reel. The coiled tubing rig
introduces the canister and inlet conduit
444 into the formation. In an embodiment, canister 442 is wound on a first
reel and inlet conduit 444 is wound on a
second reel. The coiled tubing rig introduces canister 442 into the formation.
Then, the coiled tubing rig is used to
introduce inlet conduit 444 into the canister. In other embodiments, freeze
well is assembled in sections at the
wellbore site and introduced into the formation.
An insulated section of freeze well 440 may be placed adjacent to overburden
458. An uninsulated section
of freeze well 440 may be placed adjacent to layer or layers 460 where a low
temperature zone is to be formed. In
some embodiments, uninsulated sections of the freeze wells may be positioned
adjacent only to aquifers or other
permeable portions of the formation that would allow fluid to flow into or out
of the treatment area. Portions of the
formation where uninsulated sections of the freeze wells are to be placed may
be determined using analysis of cores
and/or logging techniques.
Various types of refrigeration systems may be used to form a low temperature
zone. Determination of an
appropriate refrigeration system may be based on many factors, including, but
not limited to: a type of freeze well; a
distance between adjacent freeze wells; a refrigerant; a time frame in which
to form a low temperature zone; a depth
of the low temperature zone; a temperature differential to which the
refrigerant will be subjected; one or more
chemical and/or physical properties of the refrigerant; one or more
environmental concerns related to potential
refrigerant releases, leaks or spills; one or more economic factors; water
flow rate in the formation; composition
and/or properties of formation water including the salinity of the formation
water; and one or more properties of the
formation such as thermal conductivity, thermal diffusivity, and heat
capacity.
A circulated fluid refrigeration system may utilize a liquid refrigerant
(formation refrigerant) that is
circulated through freeze wells. Some of the desired properties for the
formation refrigerant are: low working
temperature, low viscosity at and near the working temperature, high density,
high specific heat capacity, high
thermal conductivity, low cost, low corrosiveness, and low toxicity. A low
working temperature of the formation
refrigerant allows a large low temperature zone to be established around a
freeze well. The low working temperature
of formation refrigerant should be about -20 C or lower. Formation
refrigerants having low working temperatures
of at least -60 C may include aqua ammonia, potassium formate solutions such
as Dynalenee HC-50 (Dynalenee
Heat Transfer Fluids (Whitehall, Pennsylvania, U.S.A.)) or FREEZIUM (Kemira
Chemicals (Helsinki, Finland));
silicone heat transfer fluids such as Syltherm XLT (Dow Corning Corporation
(Midland, Michigan, U.S.A.);
hydrocarbon refrigerants such as propylene; and chlorofluorocarbons such as R-
22. Aqua ammonia is a solution of
ammonia and water with a weight percent of ammonia between about 20% and about
40%. Aqua ammonia has
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CA 02871784 2014-11-18
several properties and characteristics that make use of aqua ammonia as the
formation refrigerant desirable. Such
properties and characteristics include, but are not limited to, a very low
freezing point, a low viscosity, ready
availability, and low cost.
Formation refrigerant that is capable of being chilled below a freezing
temperature of aqueous formation
.5 fluid may be used to form the low temperature zone around the treatment
area. The following equation (the Sanger
equation) may be used to model the time t1 needed to form a frozen barrier of
radius R around a freeze well having a
surface temperature of Ts:
( 2 (
= R L, R
2)
_______________________ 2 In 1+ c V
4k./ vs ro LI .1
in which:
2
1 0a, ¨1
L, = L ________________________ cvõ
2 In a,
= RA
In these equations, kfis the thermal conductivity of the frozen material; cvf
and cvõ are the volumetric heat capacity of
the frozen and unfrozen material, respectively; r, is the radius of the freeze
well; vs is the temperature difference
between the freeze well surface temperature 7', and the freezing point of
water To; vo is the temperature difference
15 between the ambient ground temperature 7" and the freezing point of
water To; L is the volumetric latent heat of
freezing of the formation; R is the radius at the frozen-unfrozen interface;
and RA is a radius at which there is no
influence from the refrigeration pipe. The Sanger equation may provide a
conservative estimate of the time needed
to form a frozen barrier of radius R because the equation does not take into
consideration superposition of cooling
from other freeze wells. The temperature of the formation refrigerant is an
adjustable variable that may significantly
20 affect the spacing between freeze wells.
EQN. 2 implies that a large low temperature zone may be formed by using a
refrigerant having an initial
temperature that is very low. The use of formation refrigerant having an
initial cold temperature of about -30 C or
lower is desirable. Formation refrigerants having initial temperatures warmer
than about -30 C may also be used,
but such formation refrigerants require longer times for the low temperature
zones produced by individual freeze
25 wells to connect. In addition, such formation refrigerants may require
the use of closer freeze well spacings and/or
more freeze wells.
The physical properties of the material used to construct the freeze wells may
be a factor in the
determination of the coldest temperature of the formation refrigerant used to
form the low temperature zone around
the treatment area. Carbon steel may be used as a construction material of
freeze wells. ASTM A333 grade 6 steel
30 alloys and ASTM A333 grade 3 steel alloys may be used for low
temperature applications. ASTM A333 grade 6
steel alloys typically contain little or no nickel and have a low working
temperature limit of about -50 'C. ASTM
A333 grade 3 steel alloys typically contain nickel and have a much colder low
working temperature limit. The
nickel in the ASTM A333 grade 3 alloy adds ductility at cold temperatures, but
also significantly raises the cost of
the metal. In some embodiments, the coldest temperature of the refrigerant is
from about -35 C to about -55 C,
35 from about -38 C to about -47 C, or from about -40 C to about -45 C
to allow for the use of ASTM A333 grade 6
steel alloys for construction of canisters for freeze wells. Stainless steels,
such as 304 stainless steel, may be used to
form freeze wells, but the cost of stainless steel is typically much more than
the cost of ASTM A333 grade 6 steel
alloy.
64
CA 02871784 2014-11-18
In some embodiments, the metal used to form the canisters of the freeze wells
may be provided as pipe. In
some embodiments, the metal used to form the canisters of the freeze wells may
be provided in sheet form. The
sheet metal may be longitudinally welded to form pipe and/or coiled tubing.
Forming the canisters from sheet metal
may improve the economics of the system by allowing for coiled tubing
insulation and by reducing the equipment
and manpower needed to form and install the canisters using pipe.
A refrigeration unit may be used to reduce the temperature of formation
refrigerant to the low working
temperature. In some embodiments, the refrigeration unit may utilize an
ammonia vaporization cycle. Refrigeration
units are available from Cool Man Inc. (Milwaukee, Wisconsin, U.S.A.), Gartner
Refrigeration & Manufacturing
(Minneapolis, Minnesota, U.S.A.), and other suppliers. In some embodiments, a
cascading refrigeration system may
be utilized with a first stage of ammonia and a second stage of carbon
dioxide. The circulating refrigerant through
the freeze wells may be 30% by weight ammonia in water (aqua ammonia).
Alternatively, a single stage carbon
dioxide refrigeration system may be used.
In some embodiments, refrigeration systems for forming a low temperature
barrier for a treatment area may
be installed and activated before freeze wells are formed in the formation. As
the freeze well wellbores are formed,
freeze wells may be installed in the wellbores. Refrigerant may be circulated
through the wellbores soon after the
= freeze well is installed into the wellbore. Limiting the time between
wellbore formation and cooling initiation may
limit or inhibit cross mixing of formation water between different aquifers.
Grout may be used in combination with freeze wells to provide a barrier for
the in situ heat treatment
process. The grout fills cavities (vugs) in the formation and reduces the
permeability of the formation. Grout may
have higher thermal conductivity than gas and/or formation fluid that fills
cavities in the formation. Placing grout in
the cavities may allow for faster low temperature zone formation. The grout
forms a perpetual barrier in the
formation that may strengthen the formation. The use of grout in
unconsolidated or substantially unconsolidated
formation material may allow for larger well spacing than is possible without
the use of grout. The combination of
grout and the low temperature zone formed by freeze wells may constitute a
double barrier for environmental
regulation purposes. In some embodiments, the grout is introduced into the
formation as a liquid, and the liquid sets
in the formation to form a solid. The grout may be any type of grout,
including but not limited to, fine cement,
micro fine cement, sulfur, sulfur cement, viscous thermoplastics, and/or
waxes. The grout may include surfactants,
stabilizers or other chemicals that modify the properties of the grout. For
example, the presence of surfactant in the
grout may promote entry of the grout into small openings in the formation.
Grout may be introduced into the formation through freeze well wellbores. The
grout may be allowed to
set. The integrity of the grout wall may be checked. The integrity of the
grout wall may be checked by logging
techniques and/or by hydrostatic testing. If the permeability of a grouted
section is too high, additional grout may be
introduced into the formation through freeze well wellbores. After the
permeability of the grouted section is
sufficiently reduced, freeze wells may be installed in the freeze well
wellbores.
Grout may be injected into the formation at a pressure that is high, but below
the fracture pressure of the
formation. In some embodiments, grouting is performed in 16 m increments in
the freeze wellbore. Larger or
smaller increments may be used if desired. In some embodiments, grout is only
applied to certain portions of the
formation. For example, grout may be applied to the formation through the
freeze wellbore only adjacent to aquifer
zones and/or to relatively high permeability zones (for example, zones with a
permeability greater than about 0.1
darcy). Applying grout to aquifers may inhibit migration of water from one
aquifer to a different aquifer. For grout
placed in the formation through freeze well wellbores, the grout may inhibit
water migration between aquifers during
CA 02871784 2014-11-18
formation of the low temperature zone. The grout may also inhibit water
migration between aquifers when an
established low temperature zone is allowed to thaw.
In some embodiments, the grout used to form a barrier may be fine cement and
micro fine cement. Cement
may provide structural support in the formation. Fine cement may be ASTM type
3 Portland cement. Fine cement
may be less expensive than micro fine cement. In an embodiment, a freeze
wellbore is formed in the formation.
Selected portions of the freeze wellbore are grouted using fine cement. Then,
micro fine cement is injected into the
formation through the freeze wellbore. The fine cement may reduce the
permeability down to about 10 millidarcy.
The micro fine cement may further reduce the permeability to about 0.1
millidarcy. After the grout is introduced
into the formation, a freeze wellbore canister may be inserted into the
formation. The process may be repeated for
each freeze well that will be used to form the barrier.
In some embodiments, fine cement is introduced into every other freeze
wellbore. Micro fine cement is
introduced into the remaining wellbores. For example, grout may be used in a
formation with freeze wellbores set at
about 5 m spacing. A first wellbore is drilled and fine cement is introduced
into the formation through the wellbore.
A freeze well canister is positioned in the first wellbore. A second wellbore
is drilled 10 m away from the first
wellbore. Fine cement is introduced into the formation through the second
wellbore. A freeze well canister is
positioned in the second wellbore. A third wellbore is drilled between the
first wellbore and the second wellbore. In
some embodiments, grout from the first ancUor second wellbores may be detected
in the cuttings of the third
wellbore. Micro fine cement is introduced into the formation through the third
wellbore. A freeze wellbore canister
is positioned in the third wellbore. The same procedure is used to form the
remaining freeze wells that will form the
barrier around the treatment area.
In some embodiments, wax may be used to form a grout barrier. Wax barriers may
be formed in wet, dry or
oil wetted formations. Liquid wax introduced into the formation may permeate
into adjacent rock and fractures in
the formation. Liquid wax may permeate into rock to fill microscopic as well
as macroscopic pores and vugs in the
rock. The wax solidifies to form a grout barrier that inhibits fluid flow into
or out of a treatment area. A wax grout
barrier may provide a minimal amount of structural support in the formation.
Molten wax may reduce the strength
of poorly consolidated soil by reducing inter-grain friction so that the
poorly consolidated soil sloughs or liquefies.
Poorly consolidated layers may be consolidated by use of cement or other
binding agents before introduction of
molten wax.
The wax of a barrier may be a branched paraffin to, for example, inhibit
biological degradation of the wax.
The wax may include stabilizers, surfactants or other chemicals that modify
the physical and/or chemical properties
of the wax. The physical properties may be tailored to meet specific needs.
The wax may melt at a relative low
temperature (for example, the wax may have a typical melting point of about 52
'V). The temperature at which the
wax congeals may be at least 5 C, 10 C, 20 C, or 30 C above the ambient
temperature of the formation prior to
any heating of the formation. When molten, the wax may have a relatively low
viscosity (for example, 4 to 10 cp at
about 99 C). The flash point of the wax may be relatively high (for example,
the flash point may be over 204 C).
The wax may have a density less than the density of water and may have a heat
capacity that is less than half the heat
capacity of water. The solid wax may have a low thermal conductivity (for
example, about 0.18 W/m C) so that the
solid wax is a thermal insulator. Waxes suitable for forming a barrier are
available as WAXFIXTM from Carter
Technologies Company (Sugar Land, Texas, U.S.A.).
In some embodiments, a wax barrier or wax barriers may be used as the barriers
for the in situ heat
treatment process. In some embodiments, a wax barrier may be used in
conjunction with freeze wells that form a
low temperature barrier around the treatment area. In some embodiments, the
wax barrier is formed and freeze wells
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CA 02871784 2014-11-18
are installed in the wellbores used for introducing wax into the formation. In
some embodiments, the wax barrier is
formed in wellbores offset from the freeze well wellbores. The wax barrier may
be on the outside or the inside of
the freeze wells. In some embodiments, a wax barrier may be formed on both the
inside and outside of the freeze
wells. The wax barrier may inhibit water flow in the formation that would
inhibit the formation of the low
temperature zone by the freeze wells. In some embodiments, a wax barrier is
formed in the inter-barrier zone
between two freeze barriers of a double barrier system.
Wellbores may be formed in the formation around the treatment area at a close
spacing. In some
embodiments, the spacing is from about 1.5 m to about 4 m. Low temperature
heaters may be inserted in the
wellbores. The heaters may operate at temperatures from about 260 C to about
320 C so that the temperature at
the formation face is below the pyrolysis temperature of hydrocarbons in the
formation. The heaters may be
activated to heat the formation until the overlap between two adjacent heaters
raises the temperature of the zone
between the two heaters above the melting temperature of the wax. Heating the
formation to obtain superposition of
heat with a temperature above the melting temperature of the wax may take one
month, two months, or longer. After
heating, the heaters may be turned off. Wax may be introduced into the
wellbores to form the barrier. The wax may
flow into the formation and fill any fractures and porosity that has been
heated. The wax congeals when the wax
flows to cold regions beyond the heated circumference. This wax barrier
formation method may form a more
complete barrier than some other methods of wax barrier formation, but the
time for heating may be longer than for
some of the other methods. Also, if a low temperature barrier is to be formed
with the freeze wells placed in the
wellbores used for wax injection, the freeze wells will have to remove the
heat supplied to the formation to allow for
introduction of the wax. The low temperature barrier may take longer to form.
In some embodiments, the wax barrier may be formed using a conduit placed in
the wellbore. FIG. I8A
depicts an embodiment of a system for forming a wax barrier in a formation.
Wellbore 452 may extend into one or
more layers 460 below overburden 458. Wellbore 452 may be an open wellbore
below underburden 458. One or
more of the layers 460 may include fracture systems 462. One or more of the
layers may be vuggy so that the layer
or a portion of the layer has a high porosity. Conduit 464 may be positioned
in wellbore 452. In some
embodiments, low temperature heater 466 may be strapped or attached to conduit
464. In some embodiments,
conduit 464 may be a heater element. Heater 466 may be operated so that the
heater does not cause pyrolysis of
hydrocarbons adjacent to the heater. At least a portion of wellbore 452 may be
filled with fluid. The fluid may be
formation fluid or water. Heater 466 may be activated to heat the fluid. A
portion of the heated fluid may move
outwards from heater 466 into the formation. The heated fluid may be injected
into the fractures and permeable
vuggy zones. The heated fluid may be injected into the fractures and permeable
vuggy zones by introducing heated
wax into wellbore 452 in the annular space between conduit 464 and the
wellbore. The introduced wax flows to the
areas heated by the fluid and congeals when the fluid reaches cold regions not
heated by the fluid. The wax fills
fracture systems 462 and permeable vuggy pathways heated by the fluid, but the
wax may not permeate through a
significant portion of the rock matrix as when the hot wax is introduced into
a heated formation as described above.
The wax flows into fracture systems 462 a sufficient distance to join with wax
injected from an adjacent well so that
a barrier to fluid flow through the fracture systems forms when the wax
congeals. A portion of wax may congeal
along the wall of a fracture or a vug without completely blocking the fracture
or filling the vug. The congealed wax
may act as an insulator and allow additional liquid wax to flow beyond the
congealed portion to penetrate deeply
into the formation and form blockages to fluid flow when the wax cools below
the melting temperature of the wax.
Wax in the annular space of wellbore 452 between conduit 464 and the formation
may be removed through
conduit by displacing the wax with water or other fluid. Conduit 464 may be
removed and a freeze well may be
67
CA 02871784 2014-11-18
installed in the wellbore. This method may use less wax than the method
described above. The heating of the fluid
may be accomplished in less than a week or within a day. The small amount of
heat input may allow for quicker
formation of a low temperature barrier if freeze wells are to be positioned in
the wellbores used to introduce wax into
the formation.
In some embodiments, a heater may be suspended in the well without a conduit
that allows for removal of
excess wax from the wellbore. The wax may be introduced into the well. After
wax introduction, the heater may be
removed from the well. In some embodiments, a conduit may be positioned in the
wellbore, but a heater may not be
coupled to the conduit. Hot wax may be circulated through the conduit so that
the wax enters fractures systems
and/or vugs adjacent to the wellbore.
In some embodiments, wax may be used during the formation of a wellbore to
improve inter-zonal isolation
and protect a low-pressure zone from inflow from a high-pressure zone. During
wellbore formation where a high
pressure zone and a low pressure zone are penetrated by a common wellbore, it
is possible for the high pressure zone
to flow into the low pressure zone and cause an underground blowout. To avoid
this, the wellbore may be formed
through the first zone. Then, an intermediate casing may be set and cemented
through the first zone. Setting casing
may be time consuming and expensive. Instead of setting a casing, wax may be
used to seal the first zone. The wax
may also inhibit or prevent mixing of high salinity brines from lower, high
pressure zones with fresher brines in
upper, lower pressure zones.
FIG. 18B depicts wellbore 452 drilled to a first depth in formation 758. After
the surface casing for
wellbore 452 is set and cemented in place, the wellbore is drilled to the
first depth which passes through a permeable
zone, such as an aquifer. The permeable zone may be fracture system 462'. In
some embodiments, a heater is
placed in wellbore 452 to heat the vertical interval of fracture system 462'.
In some embodiments, hot fluid is
circulated in wellbore 452 to heat the vertical interval of fracture system
462'. After heating, molten wax is pumped
down wellbore 452. The molten wax flows a selected distance into fracture
system 462' before the wax cools
sufficiently to solidify and form a seal. The molten wax is introduced into
formation 758 at a pressure below the
fracture pressure of the formation. In some embodiments, pressure is
maintained on the wellhead until the wax has
solidified. In some embodiments, the wax is allowed to cool until the wax in
wellbore 452 is almost to the
congealing temperature of the wax. The wax in wellbore 452 may then be
displaced out of the wellbore. The wax
makes the portion of formation 758 near wellbore 452 into a substantially
impermeable zone. Wellbore 452 may be
drilled to depth through one or more permeable zones that are at higher
pressures than the pressure in the first
permeable zone, such as fracture system 462". Congealed wax in fracture system
462' may inhibit blowout into the
lower pressure zone. FIG. I8C depicts wellbore 452 drilled to depth with
congealed wax 492 in formation 758.
In some embodiments, wax may be used to contain and inhibit migration in a
subsurface formation that has
liquid hydrocarbon contaminants (for example, compounds such as benzene,
toluene, ethylbenzene and xylene)
condensed in fractures in the formation. The location of the contaminants may
be surrounded with heated wax
injection wells. Wax may be introduced into the wells to form an outer wax
barrier. The wax injected into the
fractures from the wax injection wells may mix with the contaminants. The
contaminants may be solubilized into
the wax. When the wax congeals, the contaminants may be permanently contained
in the solid wax phase.
In some embodiments, a composition that includes a cross-linkable polymer may
be used with or in
addition to a wax. Such composition may be provided to the formation as is
described above for the wax. The
composition may be configured to react and solidify after a selected time in
the formation, thereby allowing the
composition to be provided as a liquid to the formation. The cross-linkable
polymer may include, for example,
acrylates, methacrylates, urethanes, and/or epoxies. A cross-linking initiator
may be included in the composition.
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CA 02871784 2014-11-18
The composition may also include a cross-linking inhibitor. The cross-linking
inhibitor may be configured to
degrade while in the formation, thereby allowing the composition to solidify.
In certain embodiments, a barrier may be formed in the formation after an in
situ heat treatment process or a
solution mining process by introducing a fluid into the formation. The in situ
heat treatment process may heat the
treatment area and greatly increase the permeability of the treatment area.
The solution mining process may remove
material from the treatment area and greatly increase the permeability of the
treatment area. In certain embodiments,
the treatment area has an increased permeability of at least 0.1 darcy. In
some embodiments, the treatment area has
an increased permeability of at least 1 darcy, of at least 10 darcy, or of at
least 100 darcy. The increased
permeability allows the fluid to spread in the formation into fractures,
microfractures, and/or pore spaces in the
formation. The fluid may include wax, bitumen, heavy oil, sulfur, polymer,
saturated saline solution, and/or a
reactant or reactants that react to form a precipitate, solid or a high
viscosity fluid in the formation. In some
embodiments, bitumen, heavy oil, and/or sulfur used to form the barrier are
obtained from treatment facilities of the
in situ heat treatment process.
The fluid may be introduced into the formation as a liquid, vapor, or mixed
phase fluid. The fluid may be
introduced into a portion of the formation that is at an elevated temperature.
In some embodiments, the fluid is
introduced into the formation through wells located near a perimeter of the
treatment area. The fluid may be directed
away from the treatment area. The elevated temperature of the formation
maintains or allows the fluid to have a low
viscosity so that the fluid moves away from the wells. A portion of the fluid
may spread outwards in the formation
towards a cooler portion of the formation. In the cooler portion of the
formation, the viscosity of the fluid increases,
a portion of the fluid precipitates, and/or the fluid solidifies or thickens
so that the fluid forms the barrier to flow of
formation fluid into or out of the treatment area.
In some embodiments, a low temperature barrier formed by freeze wells
surrounds all or a portion of the
treatment area. As the fluid introduced into the formation approaches the low
temperature barrier, the temperature of
the formation becomes colder. The colder temperature increases the viscosity
of the fluid, enhances precipitation,
and/or solidifies the fluid to form the barrier to the flow of formation fluid
into or out of the formation. The fluid
may remain in the formation as a highly viscous fluid or a solid after the low
temperature barrier has dissipated.
In certain embodiments, saturated saline solution is introduced into the
formation. Components in the
saturated saline solution may precipitate out of solution when the solution
reaches a colder temperature. The
solidified particles may form the barrier to the flow of formation fluid into
or out of the formation. The solidified
components may be substantially insoluble in formation fluid.
In certain embodiments, brine is introduced into the formation as a reactant.
A second reactant, such a
carbon dioxide may be introduced into the formation to react with the brine.
The reaction may generate a mineral
complex that grows in the formation. The mineral complex may be substantially
insoluble to formation fluid. In an
embodiment, the brine solution includes a sodium and aluminum solution. The
second reactant introduced in the
formation is carbon dioxide. The carbon dioxide reacts with the brine solution
to produce dawsonite. The minerals
may solidify and form the barrier to the flow of formation fluid into or out
of the formation.
In some embodiments, the barrier may be formed using sulfur. Molten sulfur may
be introduced into the
formation through wells located near the perimeter of the treatment area. At
least a portion of the sulfur spreads
outwards from the treatment area towards a cooler portion of the formation.
The introduced sulfur spreads outward
and solidifies in the formation to form a sulfur barrier. The solidified
sulfur in the formation forms a barrier to
formation fluid flow into or out of the treatment area.
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CA 02871784 2014-11-18
A temperature monitoring system may be installed in wellbores of freeze wells
and/or in monitor wells
adjacent to the freeze wells to monitor the temperature profile of the freeze
wells and/or the low temperature zone
established by the freeze wells. The monitoring system may be used to monitor
progress of low temperature zone
formation. The monitoring system may be used to determine the location of high
temperature areas, potential
breakthrough locations, or breakthrough locations after the low temperature
zone has formed. Periodic monitoring
of the temperature profile of the freeze wells and/or low temperature zone
established by the freeze wells may allow
additional cooling to be provided to potential trouble areas before
breakthrough occurs. Additional cooling may be
provided at or adjacent to breakthroughs and high temperature areas to ensure
the integrity of the low temperature
zone around the treatment area. Additional cooling may be provided by
increasing refrigerant flow through selected
freeze wells, installing an additional freeze well or freeze wells, and/or by
providing a cryogenic fluid, such as liquid
nitrogen, to the high temperature areas. Providing additional cooling to
potential problem areas before breakthrough
occurs may be more time efficient and cost efficient than sealing a breach,
reheating a portion of the treatment area
that has been cooled by influx of fluid, and/or remediating an area outside of
the breached frozen barrier.
In some embodiments, a traveling thermocouple may be used to monitor the
temperature profile of selected
freeze wells or monitor wells. In some embodiments, the temperature monitoring
system includes thermocouples
placed at discrete locations in the wellbores of the freeze wells, in the
freeze wells, and/or in the monitoring wells.
In some embodiments, the temperature monitoring system comprises a fiber optic
temperature monitoring system.
Fiber optic temperature monitoring systems are available from Sensornet
(London, United Kingdom), Sensa
(Houston, Texas, U.S.A.), Luna Energy (Blacksburg, Virginia, U.S.A.), Lios
Technology GMBH (Cologne,
Germany), Oxford Electronics Ltd. (Hampshire, United Kingdom), and Sabeus
Sensor Systems (Calabasas,
California, U.S.A.). The fiber optic temperature monitoring system includes a
data system and one or more fiber
optic cables. The data system includes one or more lasers for sending light to
the fiber optic cable; and one or more
computers, software and peripherals for receiving, analyzing, and outputting
data. The data system may be coupled
to one or more fiber optic cables.
A single fiber optic cable may be several kilometers long. The fiber optic
cable may be installed in many
freeze wells and/or monitor wells. In some embodiments, two fiber optic cables
may be installed in each freeze well
and/or monitor well. The two fiber optic cables may be coupled. Using two
fiber optic cables per well allows for
= compensation due to optical losses that occur in the wells and allows for
better accuracy of measured temperature
profiles.
The fiber optic temperature monitoring system may be used to detect the
location of a breach or a potential
breach in a frozen barrier. The search for potential breaches may be performed
at scheduled intervals, for example,
every two or three months. To determine the location of the breach or
potential breach, flow of formation refrigerant
to the freeze wells of interest is stopped. In some embodiments, the flow of
formation refrigerant to all of the freeze
wells is stopped. The rise in the temperature profiles, as well as the rate of
change of the temperature profiles,
provided by the fiber optic temperature monitoring system for each freeze well
can be used to determine the location
of any breaches or hot spots in the low temperature zone maintained by the
freeze wells. The temperature profile
monitored by the fiber optic temperature monitoring system for the two freeze
wells closest to the hot spot or fluid
flow will show the quickest and greatest rise in temperature. A temperature
change of a few degrees Centigrade in
the temperature profiles of the freeze wells closest to a troubled area may be
sufficient to isolate the location of the
trouble area. The shut down time of flow of circulation fluid in the freeze
wells of interest needed to detect
breaches, potential breaches, and hot spots may be on the order of a few hours
or days, depending on the well
spacing and the amount of fluid flow affecting the low temperature zone.
CA 02871784 2014-11-18
Fiber optic temperature monitoring systems may also be used to monitor
temperatures in heated portions of
the formation during in situ heat treatment processes. The fiber of a fiber
optic cable used in the heated portion of
the formation may be clad with a reflective material to facilitate retention
of a signal or signals transmitted down the
fiber. In some embodiments, the fiber is clad with gold, copper, nickel,
aluminum and/or alloys thereof. The
cladding may be formed of a material that is able to withstand chemical and
temperature conditions in the heated
portion of the formation. For example, gold cladding may allow an optical
sensor to be used up to temperatures of
700 C. In some embodiments, the fiber is clad with aluminum. The fiber may be
dipped in or run through a bath of
liquid aluminum. The clad fiber may then be allowed to cool to secure the
aluminum to the fiber. The gold or
aluminum cladding may reduce hydrogen darkening of the optical fiber.
A potential source of heat loss from the heated formation is due to reflux in
wells. Refluxing occurs when
vapors condense in a well and flow into a portion of the well adjacent to the
heated portion of the formation. Vapors
may condense in the well adjacent to the overburden of the formation to form
condensed fluid. Condensed fluid
flowing into the well adjacent to the heated formation absorbs heat from the
formation. Heat absorbed by condensed
fluids cools the formation and necessitates additional energy input into the
formation to maintain the formation at a
desired temperature. Some fluids that condense in the overburden and flow into
the portion of the well adjacent to
the heated formation may react to produce undesired compounds and/or coke.
Inhibiting fluids from refluxing may
significantly improve the thermal efficiency of the in situ heat treatment
system and/or the quality of the product
produced from the in situ heat treatment system.
For some well embodiments, the portion of the well adjacent to the overburden
section of the formation is
cemented to the formation. In some well embodiments, the well includes packing
material placed near the transition
from the heated section of the formation to the overburden. The packing
material inhibits formation fluid from
passing from the heated section of the formation into the section of the
wellbore adjacent to the overburden. Cables,
conduits, devices, and/or instruments may pass through the packing material,
but the packing material inhibits
formation fluid from passing up the wellbore adjacent to the overburden
section of the formation.
In some embodiments, a gas may be introduced into the formation through
wellbores to inhibit reflux in the
wellbores. In some embodiments, gas may be introduced into wellbores that
include baffle systems to inhibit reflux
of fluid in the wellbores. The gas may be carbon dioxide, methane, nitrogen or
other desired gas.
In some well embodiments, a ball type reflux baffle system may be used in
heater wells to inhibit reflux.
FIG. 19 depicts an embodiment of ball type reflux baffle system positioned in
a cased portion of a heater well. Ball
type reflux baffle may include insert 468, and balls 470. A portion of heater
element 472 passes through insert 468.
The portion of heater element 472 that passes through insert 468 is a portion
of the heater element that does not heat
to a high temperature. Insert 468 may be made of metal, plastic and/or steel
able to withstand temperatures of over
160 'C. In an embodiment, insert 468 is made of phenolic resin.
Insert 468 may be guided down the casing of the wellbore using a coil tubing
guide string. Insert 468 may
be set in position using slips that fit in one or more indentions in the
insert, using protrusions of the insert that fit in
one or more recesses in the casing, or the insert may rest on a shoulder of
the casing. After removal of the coil
tubing guide string, balls 470 may be dropped down the casing onto insert 468.
Balls may be made of any desired
material able to withstand temperatures of over 160 C. In some embodiments,
balls 470 are made of silicon nitride.
Balls of varying diameters may be used. Balls 470 inhibit fluid convection.
During the in situ heat treatment process, heater element 472 may need to be
pulled from the well. When
heater element 472 is removed from the well, balls 470 may pass through insert
468 to the bottom of the well.
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Another heater element may be installed in the well, and additional balls may
be dropped down the well to land on
insert 468.
In some embodiments, one or more circular baffles may be coupled to a portion
of a heating element to
inhibit convection of fluid. The baffles may substantially fill the annular
space between the heating element and the
casing. The baffles may be made of an electrically insulative material such as
a ceramic, or plastic. In some
embodiments, the baffles may be made of fiberglass or silicon nitride. The
baffles may position the heating element
in the center of the casing.
The ball type baffle system and/or the circular baffle system may work better
if a gas purge is introduced
into the wellbore. The gas purge may maintain sufficient pressure in the
wellbore to inhibit fluid flow from the
heated portion of the formation into the wellbore. The gas purge may enhance
heat exchange at the baffle system to
help maintain a top portion of the baffle system colder than the lower portion
of the baffle system.
The flow of production fluid up the well to the surface is desired for some
types of wells, especially for
production wells. Flow of production fluid up the well is also desirable for
some heater wells that are used to control
pressure in the formation. The overburden, or a conduit in the well used to
transport formation fluid from the heated
portion of the formation to the surface, may be heated to inhibit condensation
on or in the conduit. Providing heat in
the overburden, however, may be costly and/or may lead to increased cracking
or coking of formation fluid as the
formation fluid is being produced from the formation.
To avoid the need to heat the overburden or to heat the conduit passing
through the overburden, one or
more diverters may be placed in the wellbore to inhibit fluid from refluxing
into the wellbore adjacent to the heated
portion of the formation. In some embodiments, the diverter retains fluid
above the heated portion of the formation.
Fluids retained in the diverter may be removed from the diverter using a pump,
gas lifting, and/or other fluid
removal technique. In certain embodiments, two or more diverters that retain
fluid above the heated portion of the
formation may be located in the production well. Two or more diverters provide
a simple way of separating initial
fractions of condensed fluid produced from the in situ heat treatment system.
A pump may be placed in each of the
diverters to remove condensed fluid from the diverters.
In some embodiments, the diverter directs fluid to a sump below the heated
portion of the formation. An
inlet for a lift system may be located in the sump. In some embodiments, the
intake of the lift system is located in
casing in the sump. In some embodiments, the intake of the lift system is
located in an open wellbore. The sump is
below the heated portion of the formation. The intake of the pump may be
located 1 m, 5 m, 10 m, 20 m or more
below the deepest heater used to heat the heated portion of the formation. The
sump may be at a cooler temperature
than the heated portion of the formation. The sump may be more than 10 C,
more than 50 C, more than 75 C, or
more than 100 C below the temperature of the heated portion of the formation.
A portion of the fluid entering the
sump may be liquid. A portion of the fluid entering the sump may condense
within the sump. The lift system moves
the fluid in the sump to the surface.
Production well lift systems may be used to efficiently transport formation
fluid from the bottom of the
production wells to the surface. Production well lift systems may provide and
maintain the maximum required well
drawdown (minimum reservoir producing pressure) and producing rates. The
production well lift systems may
operate efficiently over a wide range of high temperature/multiphase fluids
(gas/vapor/steam/water/hydrocarbon
liquids) and production rates expected during the life of a typical project.
Production well lift systems may include
dual concentric rod pump lift systems, chamber lift systems and other types of
lift systems.
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Temperature limited heaters may be in configurations and/or may include
materials that provide automatic
temperature limiting properties for the heater at certain temperatures. In
certain embodiments, ferromagnetic
materials are used in temperature limited heaters. Ferromagnetic material may
self-limit temperature at or near the
Curie temperature of the material to provide a reduced amount of heat at or
near the Curie temperature when a time-
varying current is applied to the material. In certain embodiments, the
ferromagnetic material self-limits temperature
of the temperature limited heater at a selected temperature that is
approximately the Curie temperature. In certain
embodiments, the selected temperature is within about 35 C, within about 25
C, within about 20 C, or within
about 10 C of the Curie temperature. In certain embodiments, ferromagnetic
materials are coupled with other
materials (for example, highly conductive materials, high strength materials,
corrosion resistant materials, or
combinations thereof) to provide various electrical and/or mechanical
properties. Some parts of the temperature
limited heater may have a lower resistance (caused by different geometries
and/or by using different ferromagnetic
and/or non-ferromagnetic materials) than other parts of the temperature
limited heater. Having parts of the
temperature limited heater with various materials and/or dimensions allows for
tailoring the desired heat output from
each part of the heater.
Temperature limited heaters may be more reliable than other heaters.
Temperature limited heaters may be
less apt to break down or fail due to hot spots in the formation. In some
embodiments, temperature limited heaters
allow for substantially uniform heating of the formation. In some embodiments,
temperature limited heaters are able
to heat the formation more efficiently by operating at a higher average heat
output along the entire length of the
heater. The temperature limited heater operates at the higher average heat
output along the entire length of the heater
because power to the heater does not have to be reduced to the entire heater,
as is the case with typical constant
wattage heaters, if a temperature along any point of the heater exceeds, or is
about to exceed, a maximum operating
temperature of the heater. Heat output from portions of a temperature limited
heater approaching a Curie
temperature of the heater automatically reduces without controlled adjustment
of the time-varying current applied to
the heater. The heat output automatically reduces due to changes in electrical
properties (for example, electrical
resistance) of portions of the temperature limited heater. Thus, more power is
supplied by the temperature limited
heater during a greater portion of a heating process.
In certain embodiments, the system including temperature limited heaters
initially provides a first heat
output and then provides a reduced (second heat output) heat output, near, at,
or above the Curie temperature of an
electrically resistive portion of the heater when the temperature limited
heater is energized by a time-varying current.
The first heat output is the heat output at temperatures below which the
temperature limited heater begins to self-
limit. In some embodiments, the first heat output is the heat output at a
temperature about 50 C, about 75 C, about
100 C, or about 125 C below the Curie temperature of the ferromagnetic
material in the temperature limited heater.
The temperature limited heater may be energized by time-varying current
(alternating current or modulated
direct current) supplied at the wellhead. The wellhead may include a power
source and other components (for
example, modulation components, transformers, and/or capacitors) used in
supplying power to the temperature
limited heater. The temperature limited heater may be one of many heaters used
to heat a portion of the formation.
In certain embodiments, the temperature limited heater includes a conductor
that operates as a skin effect or
proximity effect heater when time-varying current is applied to the conductor.
The skin effect limits the depth of
current penetration into the interior of the conductor. For ferromagnetic
materials, the skin effect is dominated by
the magnetic permeability of the conductor. The relative magnetic permeability
of ferromagnetic materials is
typically between 10 and 1000 (for example, the relative magnetic permeability
of ferromagnetic materials is
typically at least 10 and may be at least 50, 100, 500, 1000 or greater). As
the temperature of the ferromagnetic
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material is raised above the Curie temperature and/or as the applied
electrical current is increased, the magnetic
permeability of the ferromagnetic material decreases substantially and the
skin depth expands rapidly (for example,
the skin depth expands as the inverse square root of the magnetic
permeability). The reduction in magnetic
permeability results in a decrease in the AC or modulated DC resistance of the
conductor near, at, or above the Curie
temperature and/or as the applied electrical current is increased. When the
temperature limited heater is powered by
a substantially constant current source, portions of the heater that approach,
reach, or are above the Curie
temperature may have reduced heat dissipation. Sections of the temperature
limited heater that are not at or near the
Curie temperature may be dominated by skin effect heating that allows the
heater to have high heat dissipation due
to a higher resistive load.
Curie temperature heaters have been used in soldering equipment, heaters for
medical applications, and
heating elements for ovens (for example, pizza ovens). Some of these uses are
disclosed in U.S. Patent Nos.
5,579,575 to Lamome et al.; 5,065,501 to Henschen et al.; and 5,512,732 to
Yagnik et al., all of which are
incorporated by reference as if fully set forth herein. U.S. Patent No.
4,849,611 to Whitney et al., which is
incorporated by reference as if fully set forth herein, describes a plurality
of discrete, spaced-apart heating units
including a reactive component, a resistive heating component, and a
temperature responsive component.
An advantage of using the temperature limited heater to heat hydrocarbons in
the formation is that the
conductor is chosen to have a Curie temperature in a desired range of
temperature operation. Operation within the
desired operating temperature range allows substantial heat injection into the
formation while maintaining the
temperature of the temperature limited heater, and other equipment, below
design limit temperatures. Design limit
temperatures are temperatures at which properties such as corrosion, creep,
and/or deformation are adversely
affected. The temperature limiting properties of the temperature limited
heater inhibit overheating or burnout of the
heater adjacent to low thermal conductivity "hot spots" in the formation. In
some embodiments, the temperature
limited heater is able to lower or control heat output and/or withstand heat
at temperatures above 25 C, 37 C, 100
C, 250 C, 500 C, 700 C, 800 C, 900 C, or higher up to 1131 C, depending
on the materials used in the heater.
The temperature limited heater allows for more heat injection into the
formation than constant wattage
heaters because the energy input into the temperature limited heater does not
have to be limited to accommodate low
thermal conductivity regions adjacent to the heater. For example, in Green
River oil shale there is a difference of at
least a factor of 3 in the thermal conductivity of the lowest richness oil
shale layers and the highest richness oil shale
layers. When heating such a formation, substantially more heat is transferred
to the formation with the temperature
limited heater than with the conventional heater that is limited by the
temperature at low thermal conductivity layers.
The heat output along the entire length of the conventional heater needs to
accommodate the low thermal
conductivity layers so that the heater does not overheat at the low thermal
conductivity layers and burn out. The heat
output adjacent to the low thermal conductivity layers that are at high
temperature will reduce for the temperature
limited heater, but the remaining portions of the temperature limited heater
that are not at high temperature will still
provide high heat output. Because heaters for heating hydrocarbon formations
typically have long lengths (for
example, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10 km),
the majority of the length of the
temperature limited heater may be operating below the Curie temperature while
only a few portions are at or near the
Curie temperature of the temperature limited heater.
The use of temperature limited heaters allows for efficient transfer of heat
to the formation. Efficient
transfer of heat allows for reduction in time needed to heat the formation to
a desired temperature. For example, in
Green River oil shale, pyrolysis typically requires 9.5 years to 10 years of
heating when using a 12 m heater well
spacing with conventional constant wattage heaters. For the same heater
spacing, temperature limited heaters may
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allow a larger average heat output while maintaining heater equipment
temperatures below equipment design limit
temperatures. Pyrolysis in the formation may occur at an earlier time with the
larger average heat output provided
by temperature limited heaters than the lower average heat output provided by
constant wattage heaters. For
example, in Green River oil shale, pyrolysis may occur in 5 years using
temperature limited heaters with a 12 m
heater well spacing. Temperature limited heaters counteract hot spots due to
inaccurate well spacing or drilling
where heater wells come too close together. In certain embodiments,
temperature limited heaters allow for increased
power output over time for heater wells that have been spaced too far apart,
or limit power output for heater wells
that are spaced too close together. Temperature limited heaters also supply
more power in regions adjacent the
overburden and underburden to compensate for temperature losses in these
regions.
Temperature limited heaters may be advantageously used in many types of
formations. For example, in tar
sands formations or relatively permeable formations containing heavy
hydrocarbons, temperature limited heaters
may be used to provide a controllable low temperature output for reducing the
viscosity of fluids, mobilizing fluids,
and/or enhancing the radial flow of fluids at or near the wellbore or in the
formation. Temperature limited heaters
may be used to inhibit excess coke formation due to overheating of the near
wellbore region of the formation.
The use of temperature limited heaters, in some embodiments, eliminates or
reduces the need for expensive
temperature control circuitry. For example, the use of temperature limited
heaters eliminates or reduces the need to
perform temperature logging and/or the need to use fixed thermocouples on the
heaters to monitor potential
overheating at hot spots.
In certain embodiments, phase transformation (for example, crystalline phase
transformation or a change in
the crystal structure) of materials used in a temperature limited heater
change the selected temperature at which the
heater self-limits. Ferromagnetic material used in the temperature limited
heater may have a phase transformation
(for example, a transformation from ferrite to austenite) that decreases the
magnetic permeability of the
ferromagnetic material. This reduction in magnetic permeability is similar to
reduction in magnetic permeability due
to the magnetic transition of the ferromagnetic material at the Curie
temperature. The Curie temperature is the
magnetic transition temperature of the ferrite phase of the ferromagnetic
material. The reduction in magnetic
permeability results in a decrease in the AC or modulated DC resistance of the
temperature limited heater near, at, or
above the temperature of the phase transformation ancUor the Curie temperature
of the ferromagnetic material.
The phase transformation of the ferromagnetic material may occur over a
temperature range. The
temperature range of the phase transformation depends on the ferromagnetic
material and may vary, for example,
over a range of about 20 C to a range of about 200 C. Because the phase
transformation takes place over a
temperature range, the reduction in the magnetic permeability due to the phase
transformation takes place over the
temperature range. The reduction in magnetic permeability may also occur
irregularly over the temperature range of
the phase transformation. In some embodiments, the phase transformation back
to the lower temperature phase of
the ferromagnetic material is slower than the phase transformation to the
higher temperature phase (for example, the
transition from austenite back to ferrite is slower than the transition from
ferrite to austenite). The slower phase
transformation back to the lower temperature phase may cause irregular
operation of the heater at or near the phase
transformation temperature range.
In some embodiments, the phase transformation temperature range overlaps with
the reduction in the
magnetic permeability when the temperature approaches the Curie temperature of
the ferromagnetic material. The
overlap may produce a slower drop in electrical resistance versus temperature
than if the reduction in magnetic
permeability is solely due to the temperature approaching the Curie
temperature. The overlap may also produce
CA 02871784 2014-11-18
irregular behavior of the temperature limited heater near the Curie
temperature and/or in the phase transformation
temperature range.
In certain embodiments, alloy additions are made to the ferromagnetic material
to adjust the temperature
range of the phase transformation. For example, adding carbon to the
ferromagnetic material may increase the phase
transformation temperature range and lower the onset temperature of the phase
transformation. Adding titanium to
the ferromagnetic material may increase the onset temperature of the phase
transformation and decrease the phase
transformation temperature range. Alloy compositions may be adjusted to
provide desired Curie temperature and
phase transformation properties for the ferromagnetic material. The alloy
composition of the ferromagnetic material
may be chosen based on desired properties for the ferromagnetic material (such
as, but not limited to, magnetic
permeability transition temperature or temperature range, resistance versus
temperature profile, or power output),
Addition of titanium may allow higher Curie temperatures to be obtained when
adding cobalt to 410 stainless steel
by raising the ferrite to austenite phase transformation temperature range to
a temperature range that is above, or
well above, the Curie temperature of the ferromagnetic material.
In certain embodiments, the temperature limited heater is deformation
tolerant. Localized movement of
material in the wellbore may result in lateral stresses on the heater that
could deform its shape. Locations along a
length of the heater at which the wellbore approaches or closes on the heater
may be hot spots where a standard
heater overheats and has the potential to burn out. These hot spots may lower
the yield strength and creep strength
of the metal, allowing crushing or deformation of the heater. The temperature
limited heater may be formed with S
curves (or other non-linear shapes) that accommodate deformation of the
temperature limited heater without causing
failure of the heater.
In some embodiments, temperature limited heaters are more economical to
manufacture or make than
standard heaters. Typical ferromagnetic materials include iron, carbon steel,
or ferritic stainless steel. Such
materials are inexpensive as compared to nickel-based heating alloys (such as
nichrome, KanthalTM (Bulten-Kanthal
AB, Sweden), and/or LOHMTm (Driver-Harris Company, Harrison, New Jersey,
U.S.A.)) typically used in insulated
conductor (mineral insulated cable) heaters. In one embodiment of the
temperature limited heater, the temperature
limited heater is manufactured in continuous lengths as an insulated conductor
heater to lower costs and improve
reliability.
In some embodiments, the temperature limited heater is placed in the heater
well using a coiled tubing rig.
A heater that can be coiled on a spool may be manufactured by using metal such
as ferritic stainless steel (for
example, 409 stainless steel) that is welded using electrical resistance
welding (ERW). To form a heater section, a
metal strip from a roll is passed through a first former where it is shaped
into a tubular and then longitudinally
welded using ERW. The tubular is passed through a second former where a
conductive strip (for example, a copper
strip) is applied, drawn down tightly on the tubular through a die, and
longitudinally welded using ERW. A sheath
may be formed by longitudinally welding a support material (for example, steel
such as 347H or 347HH) over the
conductive strip material. The support material may be a strip rolled over the
conductive strip material. An
overburden section of the heater may be formed in a similar manner.
FIG. 20 depicts an embodiment of a device for longitudinal welding of a
tubular using ERW. Metal strip
474 is shaped into tubular form as it passes through ERW coil 476. Metal strip
474 is then welded into a tubular
inside shield 478. As metal strip 474 is joined inside shield 478, inert gas
(for example, argon or another suitable
welding gas) is provided inside the forming tubular by gas inlets 480.
Flushing the tubular with inert gas inhibits
oxidation of the tubular as it is formed. Shield 478 may have window 482.
Window 482 allows an operator to
visually inspect the welding process. Tubular 484 is formed by the welding
process.
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In certain embodiments, the overburden section uses a non-ferromagnetic
material such as 304 stainless
steel or 316 stainless steel instead of a ferromagnetic material. The heater
section and overburden section may be
coupled using standard techniques such as butt welding using an orbital
welder. In some embodiments, the
overburden section material (the non-ferromagnetic material) may be pre-welded
to the ferromagnetic material
before rolling. The pre-welding may eliminate the need for a separate coupling
step (for example, butt welding). In
an embodiment, a flexible cable (for example, a furnace cable such as a MGT
1000 furnace cable) may be pulled
through the center after forming the tubular heater. An end bushing on the
flexible cable may be welded to the
tubular heater to provide an electrical current return path. The tubular
heater, including the flexible cable, may be
coiled onto a spool before installation into a heater well. In an embodiment,
the temperature limited heater is
installed using the coiled tubing rig. The coiled tubing rig may place the
temperature limited heater in a deformation
resistant container in the formation. The deformation resistant container may
be placed in the heater well using
conventional methods.
Temperature limited heaters may be used for heating hydrocarbon formations
including, but not limited to,
oil shale formations, coal formations, tar sands formations, and formations
with heavy viscous oils. Temperature
limited heaters may also be used in the field of environmental remediation to
vaporize or destroy soil contaminants.
Embodiments of temperature limited heaters may be used to heat fluids in a
wellbore or sub-sea pipeline to inhibit
deposition of paraffin or various hydrates. In some embodiments, a temperature
limited heater is used for solution
mining a subsurface formation (for example, an oil shale or a coal formation).
In certain embodiments, a fluid (for
example, molten salt) is placed in a wellbore and heated with a temperature
limited heater to inhibit deformation
and/or collapse of the wellbore. In some embodiments, the temperature limited
heater is attached to a sucker rod in
the wellbore or is part of the sucker rod itself. In some embodiments,
temperature limited heaters are used to heat a
near wellbore region to reduce near wellbore oil viscosity during production
of high viscosity crude oils and during
transport of high viscosity oils to the surface. In some embodiments, a
temperature limited heater enables gas lifting
of a viscous oil by lowering the viscosity of the oil without coking the oil.
Temperature limited heaters may be used
in sulfur transfer lines to maintain temperatures between about 110 C and
about 130 C.
The ferromagnetic alloy or ferromagnetic alloys used in the temperature
limited heater determine the Curie
temperature of the heater. Curie temperature data for various metals is listed
in "American Institute of Physics
= Handbook," Second Edition, McGraw-Hill, pages 5-170 through 5-176.
Ferromagnetic conductors may include one
or more of the ferromagnetic elements (iron, cobalt, and nickel) and/or alloys
of these elements. In some
embodiments, ferromagnetic conductors include iron-chromium (Fe-Cr) alloys
that contain tungsten (W) (for
example, HCM12A and SAVE12 (Sumitomo Metals Co., Japan) and/or iron alloys
that contain chromium (for
example, Fe-Cr alloys, Fe-Cr-W alloys, Fe-Cr-V (vanadium) alloys, and Fe-Cr-Nb
(Niobium) alloys). Of the three
main ferromagnetic elements, iron has a Curie temperature of approximately 770
C; cobalt (Co) has a Curie
temperature of approximately 1131 C; and nickel has a Curie temperature of
approximately 358 C. An iron-cobalt
alloy has a Curie temperature higher than the Curie temperature of iron. For
example, iron-cobalt alloy with 2% by
weight cobalt has a Curie temperature of approximately 800 C; iron-cobalt
alloy with 12% by weight cobalt has a
Curie temperature of approximately 900 C; and iron-cobalt alloy with 20% by
weight cobalt has a Curie
temperature of approximately 950 C. Iron-nickel alloy has a Curie temperature
lower than the Curie temperature of
iron. For example, iron-nickel alloy with 20% by weight nickel has a Curie
temperature of approximately 720 C,
and iron-nickel alloy with 60% by weight nickel has a Curie temperature of
approximately 560 C.
Some non-ferromagnetic elements used as alloys raise the Curie temperature of
iron. For example, an iron-
vanadium alloy with 5.9% by weight vanadium has a Curie temperature of
approximately 815 C. Other non-
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ferromagnetic elements (for example, carbon, aluminum, copper, silicon, and/or
chromium) may be alloyed with
iron or other ferromagnetic materials to lower the Curie temperature. Non-
ferromagnetic materials that raise the
Curie temperature may be combined with non-ferromagnetic materials that lower
the Curie temperature and alloyed
with iron or other ferromagnetic materials to produce a material with a
desired Curie temperature and other desired
physical and/or chemical properties. In some embodiments, the Curie
temperature material is a ferrite such as
NiFe204. In other embodiments, the Curie temperature material is a binary
compound such as FeNi3 or Fe3A1.
In some embodiments, the improved alloy includes carbon, cobalt, iron,
manganese, silicon, or mixtures
thereof. In certain embodiments, the improved alloy includes, by weight: about
0.1% to about 10% cobalt; about
0.1% carbon, about 0.5% manganese, about 0.5% silicon, with the balance being
iron. In certain embodiments, the
improved alloy includes, by weight: about 0.1% to about 10% cobalt; about 0.1%
carbon, about 0.5% manganese,
about 0.5% silicon, with the balance being iron.
In some embodiments, the improved alloy includes chromium, carbon, cobalt,
iron, manganese, silicon,
titanium, vanadium, or mixtures thereof. In certain embodiments, the improved
alloy includes, by weight: about 5%
to about 20% cobalt, about 0.1% carbon, about 0.5% manganese, about 0.5%
silicon, about 0.1% to about 2%
vanadium with the balance being iron. In some embodiments, the improved alloy
includes, by weight; about 12%
chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5%
manganese, above 0% to about 15%
cobalt, above 0% to about 2% vanadium, above 0% to about 1% titanium, with the
balance being iron. In some
embodiments, the improved alloy includes, by weight: about 12% chromium, about
0.1% carbon, about 0.5% silicon,
about 0.1% to about 0.5% manganese, above 0% to about 2% vanadium, above 0% to
about 1% titanium, with the
balance being iron. In some embodiments, the improved alloy includes, by
weight: about 12% chromium, about
0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0%
to about 2% vanadium, with the
balance being iron. In certain embodiments, the improved alloy includes, by
weight: about 12% chromium, about
0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0%
to about 15% cobalt, above 0% to
about 1% titanium, with the balance being iron. In certain embodiments, the
improved alloy includes, by weight:
about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about
0.5% manganese, above 0% to
about 15% cobalt, with the balance being iron. The addition of vanadium may
allow for use of higher amounts of
cobalt in the improved alloy.
Certain embodiments of temperature limited heaters may include more than one
ferromagnetic material.
Such embodiments are within the scope of embodiments described herein if any
conditions described herein apply to
at least one of the ferromagnetic materials in the temperature limited heater.
Ferromagnetic properties generally decay as the Curie temperature is
approached. The "Handbook of
Electrical Heating for Industry" by C. James Erickson (IEEE Press, 1995) shows
a typical curve for I% carbon steel
(steel with 1% carbon by weight). The loss of magnetic permeability starts at
temperatures above 650 C and tends
to be complete when temperatures exceed 730 C. Thus, the self-limiting
temperature may be somewhat below the
actual Curie temperature of the ferromagnetic conductor. The skin depth for
current flow in 1% carbon steel is 0.132
cm at room temperature and increases to 0.445 cm at 720 C. From 720 C to 730
C, the skin depth sharply
increases to over 2.5 cm. Thus, a temperature limited heater embodiment using
1% carbon steel begins to self-limit
between 650 C and 730 C.
Skin depth generally defines an effective penetration depth of time-varying
current into the conductive
material. In general, current density decreases exponentially with distance
from an outer surface to the center along
the radius of the conductor. The depth at which the current density is
approximately 1/e of the surface current
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density is called the skin depth. For a solid cylindrical rod with a diameter
much greater than the penetration depth,
or for hollow cylinders with a wall thickness exceeding the penetration depth,
the skin depth, 8, is:
(3) 6 = 1981.5* (p/(i.t*f))112;
in which: 6 = skin depth in inches;
p = resistivity at operating temperature (ohm-cm);
= relative magnetic permeability; and
f= frequency (Hz).
EQN. 3 is obtained from "Handbook of Electrical Heating for Industry" by C.
James Erickson (IEEE Press,
1995). For most metals, resistivity (p) increases with temperature. The
relative magnetic permeability generally
varies with temperature and with current. Additional equations may be used to
assess the variance of magnetic
permeability and/or skin depth on both temperature and/or current. The
dependence of p. on current arises from the
dependence of pi on the electromagnetic field.
Materials used in the temperature limited heater may be selected to provide a
desired turndown ratio.
Turndown ratios of at least 1.1:1, 2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may
be selected for temperature limited
heaters. Larger turndown ratios may also be used. A selected turndown ratio
may depend on a number of factors
including, but not limited to, the type of formation in which the temperature
limited heater is located (for example, a
higher turndown ratio may be used for an oil shale formation with large
variations in thermal conductivity between
rich and lean oil shale layers) and/or a temperature limit of materials used
in the wellbore (for example, temperature
limits of heater materials). In some embodiments, the turndown ratio is
increased by coupling additional copper or
another good electrical conductor to the ferromagnetic material (for example,
adding copper to lower the resistance
above the Curie temperature).
The temperature limited heater may provide a maximum heat output (power
output) below the Curie
temperature of the heater. In certain embodiments, the maximum heat output is
at least 400 W/m (Watts per meter),
600 W/m, 700 W/m, 800 W/m, or higher up to 2000 W/m. The temperature limited
heater reduces the amount of
heat output by a section of the heater when the temperature of the section of
the heater approaches or is above the
Curie temperature. The reduced amount of heat may be substantially less than
the heat output below the Curie
temperature. In some embodiments, the reduced amount of heat is at most 400
W/m, 200 W/m, 100 W/m or may
approach 0 W/m.
In certain embodiments, the temperature limited heater operates substantially
independently of the thermal
load on the heater in a certain operating temperature range. "Thermal load" is
the rate that heat is transferred from a
heating system to its surroundings. It is to be understood that the thermal
load may vary with temperature of the
surroundings and/or the thermal conductivity of the surroundings. In an
embodiment, the temperature limited heater
operates at or above the Curie temperature of the temperature limited heater
such that the operating temperature of
the heater increases at most by 3 C, 2 C, 1.5 C, 1 C, or 0.5 C for a
decrease in thermal load of 1 W/m proximate
to a portion of the heater. In certain embodiments, the temperature limited
heater operates in such a manner at a
relatively constant current.
The AC or modulated DC resistance and/or the heat output of the temperature
limited heater may decrease
as the temperature approaches the Curie temperature and decrease sharply near
or above the Curie temperature due
to the Curie effect. In certain embodiments, the value of the electrical
resistance or heat output above or near the
Curie temperature is at most one-half of the value of electrical resistance or
heat output at a certain point below the
Curie temperature. In some embodiments, the heat output above or near the
Curie temperature is at most 90%, 70%,
50%, 30%, 20%, 10%, or less (down to 1%) of the heat output at a certain point
below the Curie temperature (for
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CA 02871784 2014-11-18
example, 30 C below the Curie temperature, 40 C below the Curie temperature,
50 C below the Curie
temperature, or 100 C below the Curie temperature). In certain embodiments,
the electrical resistance above or near
the Curie temperature decreases to 80%, 70%, 60%, 50%, or less (down to 1%) of
the electrical resistance at a
certain point below the Curie temperature (for example, 30 C below the Curie
temperature, 40 C below the Curie
temperature, 50 C below the Curie temperature, or 100 C below the Curie
temperature).
In some embodiments, AC frequency is adjusted to change the skin depth of the
ferromagnetic material.
For example, the skin depth of 1% carbon steel at room temperature is 0.132 cm
at 60 Hz, 0.0762 cm at 180 Hz, and
0.046 cm at 440 Hz. Since heater diameter is typically larger than twice the
skin depth, using a higher frequency
(and thus a heater with a smaller diameter) reduces heater costs. For a fixed
geometry, the higher frequency results
in a higher turndown ratio. The turndown ratio at a higher frequency is
calculated by multiplying the turndown ratio
at a lower frequency by the square root of the higher frequency divided by the
lower frequency. In some
embodiments, a frequency between 100 Hz and 1000 Hz, between 140 Hz and 200
Hz, or between 400 Hz and 600
Hz is used (for example, 180 Hz, 540 Hz, or 720 Hz). In some embodiments, high
frequencies may be used. The
frequencies may be greater than 1000 Hz.
To maintain a substantially constant skin depth until the Curie temperature of
the temperature limited heater
is reached, the heater may be operated at a lower frequency when the heater is
cold and operated at a higher
frequency when the heater is hot. Line frequency heating is generally
favorable, however, because there is less need
for expensive components such as power supplies, transformers, or current
modulators that alter frequency. Line
frequency is the frequency of a general supply of current. Line frequency is
typically 60 Hz, but may be 50 Hz or
another frequency depending on the source for the supply of the current.
Higher frequencies may be produced using
commercially available equipment such as solid state variable frequency power
supplies. Transformers that convert
three-phase power to single-phase power with three times the frequency are
commercially available. For example,
high voltage three-phase power at 60 Hz may be transformed to single-phase
power at 180 Hz and at a lower
voltage. Such transformers are less expensive and more energy efficient than
solid state variable frequency power
supplies. In certain embodiments, transformers that convert three-phase power
to single-phase power are used to
increase the frequency of power supplied to the temperature limited heater.
In certain embodiments, modulated DC (for example, chopped DC, waveform
modulated DC, or cycled
DC) may be used for providing electrical power to the temperature limited
heater. A DC modulator or DC chopper
may be coupled to a DC power supply to provide an output of modulated direct
current. In some embodiments, the
DC power supply may include means for modulating DC. One example of a DC
modulator is a DC-to-DC converter
system. DC-to-DC converter systems are generally known in the art. DC is
typically modulated or chopped into a
desired waveform. Waveforms for DC modulation include, but are not limited to,
square-wave, sinusoidal,
deformed sinusoidal, deformed square-wave, triangular, and other regular or
irregular waveforms.
The modulated DC waveform generally defines the frequency of the modulated DC.
Thus, the modulated
DC waveform may be selected to provide a desired modulated DC frequency. The
shape and/or the rate of
modulation (such as the rate of chopping) of the modulated DC waveform may be
varied to vary the modulated DC
frequency. DC may be modulated at frequencies that are higher than generally
available AC frequencies. For
example, modulated DC may be provided at frequencies of at least 1000 Hz.
Increasing the frequency of supplied
current to higher values advantageously increases the turndown ratio of the
temperature limited heater.
In certain embodiments, the modulated DC waveform is adjusted or altered to
vary the modulated DC
frequency. The DC modulator may be able to adjust or alter the modulated DC
waveform at any time during use of
the temperature limited heater and at high currents or voltages. Thus,
modulated DC provided to the temperature
CA 02871784 2014-11-18
limited heater is not limited to a single frequency or even a small set of
frequency values. Waveform selection using
the DC modulator typically allows for a wide range of modulated DC frequencies
and for discrete control of the
modulated DC frequency. Thus, the modulated DC frequency is more easily set at
a distinct value whereas AC
frequency is generally limited to multiples of the line frequency. Discrete
control of the modulated DC frequency
allows for more selective control over the turndown ratio of the temperature
limited heater. Being able to selectively
control the turndown ratio of the temperature limited heater allows for a
broader range of materials to be used in
designing and constructing the temperature limited heater.
In some embodiments, the modulated DC frequency or the AC frequency is
adjusted to compensate for
changes in properties (for example, subsurface conditions such as temperature
or pressure) of the temperature limited
heater during use. The modulated DC frequency or the AC frequency provided to
the temperature limited heater is
varied based on assessed downhole conditions. For example, as the temperature
of the temperature limited heater in
the wellbore increases, it may be advantageous to increase the frequency of
the current provided to the heater, thus
increasing the turndown ratio of the heater. In an embodiment, the downhole
temperature of the temperature limited
heater in the wellbore is assessed.
In certain embodiments, the modulated DC frequency, or the AC frequency, is
varied to adjust the
turndown ratio of the temperature limited heater. The turndown ratio may be
adjusted to compensate for hot spots
occurring along a length of the temperature limited heater. For example, the
turndown ratio is increased because the
temperature limited heater is getting too hot in certain locations. In some
embodiments, the modulated DC
frequency, or the AC frequency, are varied to adjust a turndown ratio without
assessing a subsurface condition.
At or near the Curie temperature of the ferromagnetic material, a relatively
small change in voltage may
cause a relatively large change in current to the load. The relatively small
change in voltage may produce problems
in the power supplied to the temperature limited heater, especially at or near
the Curie temperature. The problems
include, but are not limited to, reducing the power factor, tripping a circuit
breaker, and/or blowing a fuse. In some
cases, voltage changes may be caused by a change in the load of the
temperature limited heater. In certain
embodiments, an electrical current supply (for example, a supply of modulated
DC or AC) provides a relatively
constant amount of current that does not substantially vary with changes in
load of the temperature limited heater. In
an embodiment, the electrical current supply provides an amount of electrical
current that remains within 15%,
within 10%, within 5%, or within 2% of a selected constant current value when
a load of the temperature limited
heater changes.
Temperature limited heaters may generate an inductive load. The inductive load
is due to some applied
electrical current being used by the ferromagnetic material to generate a
magnetic field in addition to generating a
resistive heat output. As downhole temperature changes in the temperature
limited heater, the inductive load of the
heater changes due to changes in the ferromagnetic properties of ferromagnetic
materials in the heater with
temperature. The inductive load of the temperature limited heater may cause a
phase shift between the current and
the voltage applied to the heater.
A reduction in actual power applied to the temperature limited heater may be
caused by a time lag in the
current waveform (for example, the current has a phase shift relative to the
voltage due to an inductive load) and/or
by distortions in the current waveform (for example, distortions in the
current waveform caused by introduced
harmonics due to a non-linear load). Thus, it may take more current to apply a
selected amount of power due to
phase shifting or waveform distortion. The ratio of actual power applied and
the apparent power that would have
been transmitted if the same current were in phase and undistorted is the
power factor. The power factor is always
less than or equal to I. The power factor is 1 when there is no phase shift or
distortion in the waveform.
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Actual power applied to a heater due to a phase shift may be described by EQN.
4:
(4) P=I x V x cos(0);
in which P is the actual power applied to a heater; I is the applied current;
V is the applied voltage; and 0 is the phase
angle difference between voltage and current. Other phenomena such as waveform
distortion may contribute to
further lowering of the power factor. If there is no distortion in the
waveform, then cos(0) is equal to the power
factor.
In certain embodiments, the temperature limited heater includes an inner
conductor inside an outer
conductor. The inner conductor and the outer conductor are radially disposed
about a central axis. The inner and
outer conductors may be separated by an insulation layer. In certain
embodiments, the inner and outer conductors
are coupled at the bottom of the temperature limited heater. Electrical
current may flow into the temperature limited
heater through the inner conductor and return through the outer conductor. One
or both conductors may include
ferromagnetic material.
The insulation layer may comprise an electrically insulating ceramic with high
thermal conductivity, such
as magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron
nitride, silicon nitride, or
combinations thereof. The insulating layer may be a compacted powder (for
example, compacted ceramic powder).
Compaction may improve thermal conductivity and provide better insulation
resistance. For lower temperature
applications, polymer insulation made from, for example, fluoropolymers,
polyimides, polyamides, and/or
polyethylenes, may be used. In some embodiments, the polymer insulation is
made of perfluoroallcoxy (PFA) or
polyetheretherketone (PEEKTM (Victrex Ltd, England)). The insulating layer may
be chosen to be substantially
infrared transparent to aid heat transfer from the inner conductor to the
outer conductor. In an embodiment, the
insulating layer is transparent quartz sand. The insulation layer may be air
or a non-reactive gas such as helium,
nitrogen, or sulfur hexafluoride. If the insulation layer is air or a non-
reactive gas, there may be insulating spacers
designed to inhibit electrical contact between the inner conductor and the
outer conductor. The insulating spacers
may be made of, for example, high purity aluminum oxide or another thermally
conducting, electrically insulating
material such as silicon nitride. The insulating spacers may be a fibrous
ceramic material such as NextelTM 312 (3M
Corporation, St. Paul, Minnesota, U.S.A.), mica tape, or glass fiber. Ceramic
material may be made of alumina,
alumina-silicate, alumina-borosilicate, silicon nitride, boron nitride, or
other materials.
The insulation layer may be flexible and/or substantially deformation
tolerant. For example, if the
insulation layer is a solid or compacted material that substantially fills the
space between the inner and outer
conductors, the temperature limited heater may be flexible and/or
substantially deformation tolerant. Forces on the
outer conductor can be transmitted through the insulation layer to the solid
inner conductor, which may resist
crushing. Such a temperature limited heater may be bent, dog-legged, and
spiraled without causing the outer
conductor and the inner conductor to electrically short to each other.
Deformation tolerance may be important if the
wellbore is likely to undergo substantial deformation during heating of the
formation.
In certain embodiments, an outermost layer of the temperature limited heater
(for example, the outer
conductor) is chosen for corrosion resistance, yield strength, and/or creep
resistance. In one embodiment, austenitic
(non-ferromagnetic) stainless steels such as 201, 304H, 347H, 347HH, 316H,
310H, 3471-IP, NF709 (Nippon Steel
Corp., Japan) stainless steels, or combinations thereof may be used in the
outer conductor. The outermost layer may
also include a clad conductor. For example, a corrosion resistant alloy such
as 800H or 347H stainless steel may be
clad for corrosion protection over a ferromagnetic carbon steel tubular. If
high temperature strength is not required,
the outermost layer may be constructed from ferromagnetic metal with good
corrosion resistance such as one of the
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ferritic stainless steels. In one embodiment, a ferritic alloy of 82.3% by
weight iron with 17.7% by weight
chromium (Curie temperature of 678 C) provides desired corrosion resistance.
The Metals Handbook, vol. 8, page 291 (American Society of Materials (ASM))
includes a graph of Curie
temperature of iron-chromium alloys versus the amount of chromium in the
alloys. In some temperature limited
heater embodiments, a separate support rod or tubular (made from 347H
stainless steel) is coupled to the temperature
limited heater made from an iron-chromium alloy to provide yield strength
and/or creep resistance. In certain
embodiments, the support material and/or the ferromagnetic material is
selected to provide a 100,000 hour creep-
rupture strength of at least 20.7 MPa at 650 C. In some embodiments, the
100,000 hour creep-rupture strength is at
least 13.8 MPa at 650 C or at least 6.9 MPa at 650 C. For example, 347H
steel has a favorable creep-rupture
strength at or above 650 C. In some embodiments, the 100,000 hour creep-
rupture strength ranges from 6.9 MPa to
41.3 MPa or more for longer heaters and/or higher earth or fluid stresses.
In temperature limited heater embodiments with both an inner ferromagnetic
conductor and an outer
ferromagnetic conductor, the skin effect current path occurs on the outside of
the inner conductor and on the inside
of the outer conductor. Thus, the outside of the outer conductor may be clad
with the corrosion resistant alloy, such
as stainless steel, without affecting the skin effect current path on the
inside of the outer conductor.
A ferromagnetic conductor with a thickness of at least the skin depth at the
Curie temperature allows a
substantial decrease in resistance of the ferromagnetic material as the skin
depth increases sharply near the Curie
temperature. In certain embodiments when the ferromagnetic conductor is not
clad with a highly conducting
material such as copper, the thickness of the conductor may be 1.5 times the
skin depth near the Curie temperature, 3
times the skin depth near the Curie temperature, or even 10 or more times the
skin depth near the Curie temperature.
If the ferromagnetic conductor is clad with copper, thickness of the
ferromagnetic conductor may be substantially the
same as the skin depth near the Curie temperature. In some embodiments, the
ferromagnetic conductor clad with
copper has a thickness of at least three-fourths of the skin depth near the
Curie temperature.
In certain embodiments, the temperature limited heater includes a composite
conductor with a
ferromagnetic tubular and a non-ferromagnetic, high electrical conductivity
core. The non-ferromagnetic, high
electrical conductivity core reduces a required diameter of the conductor. For
example, the conductor may be
composite 1.19 cm diameter conductor with a core of 0.575 cm diameter copper
clad with a 0.298 cm thickness of
terrific stainless steel or carbon steel surrounding the core. The core or non-
ferromagnetic conductor may be copper
or copper alloy. The core or non-ferromagnetic conductor may also be made of
other metals that exhibit low
electrical resistivity and relative magnetic permeabilities near I (for
example, substantially non-ferromagnetic
materials such as aluminum and aluminum alloys, phosphor bronze, beryllium
copper, and/or brass). A composite
conductor allows the electrical resistance of the temperature limited heater
to decrease more steeply near the Curie
temperature. As the skin depth increases near the Curie temperature to include
the copper core, the electrical
resistance decreases very sharply.
The composite conductor may increase the conductivity of the temperature
limited heater and/or allow the
heater to operate at lower voltages. In an embodiment, the composite conductor
exhibits a relatively flat resistance
versus temperature profile at temperatures below a region near the Curie
temperature of the ferromagnetic conductor
of the composite conductor. In some embodiments, the temperature limited
heater exhibits a relatively flat resistance
versus temperature profile between 100 C and 750 C or between 300 C and 600
C. The relatively flat resistance
versus temperature profile may also be exhibited in other temperature ranges
by adjusting, for example, materials
and/or the configuration of materials in the temperature limited heater. In
certain embodiments, the relative
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thickness of each material in the composite conductor is selected to produce a
desired resistivity versus temperature
profile for the temperature limited heater.
In certain embodiments, the relative thickness of each material in a composite
conductor is selected to
produce a desired resistivity versus temperature profile for a temperature
limited heater. In an embodiment, the
composite conductor is an inner conductor surrounded by 0.127 cm thick
magnesium oxide powder as an insulator.
The outer conductor may be 304H stainless steel with a wall thickness of 0.127
cm. The outside diameter of the
heater may be about 1.65 cm.
A composite conductor (for example, a composite inner conductor or a composite
outer conductor) may be
manufactured by methods including, but not limited to, coextrusion, roll
forming, tight fit tubing (for example,
cooling the inner member and heating the outer member, then inserting the
inner member in the outer member,
followed by a drawing operation and/or allowing the system to cool), explosive
or electromagnetic cladding, arc
overlay welding, longitudinal strip welding, plasma powder welding, billet
coextrusion, electroplating, drawing,
sputtering, plasma deposition, coextrusion casting, magnetic forming, molten
cylinder casting (of inner core material
inside the outer or vice versa), insertion followed by welding or high
temperature braising, shielded active gas
welding (SAG), and/or insertion of an inner pipe in an outer pipe followed by
mechanical expansion of the inner
pipe by hydroforming or use of a pig to expand and swage the inner pipe
against the outer pipe. In some
embodiments, a ferromagnetic conductor is braided over a non-ferromagnetic
conductor. In certain embodiments,
composite conductors are formed using methods similar to those used for
cladding (for example, cladding copper to
steel). A metallurgical bond between copper cladding and base ferromagnetic
material may be advantageous.
Composite conductors produced by a coextrusion process that forms a good
metallurgical bond (for example, a good
bond between copper and 446 stainless steel) may be provided by Anomet
Products, Inc. (Shrewsbury,
Massachusetts, U.S.A.).
FIGS. 21-42 depict various embodiments of temperature limited heaters. One or
more features of an
embodiment of the temperature limited heater depicted in any of these figures
may be combined with one or more
features of other embodiments of temperature limited heaters depicted in these
figures. In certain embodiments
described herein, temperature limited heaters are dimensioned to operate at a
frequency of 60 Hz AC. It is to be
understood that dimensions of the temperature limited heater may be adjusted
from those described herein to operate
in a similar manner at other AC frequencies or with modulated DC current.
FIG. 21 depicts a cross-sectional representation of an embodiment of the
temperature limited heater with an
outer conductor having a ferromagnetic section and a non-ferromagnetic
section. FIGS. 22 and 23 depict transverse
cross-sectional views of the embodiment shown in FIG. 21. In one embodiment,
ferromagnetic section 486 is used
to provide heat to hydrocarbon layers in the formation. Non-ferromagnetic
section 488 is used in the overburden of
the formation. Non-ferromagnetic section 488 provides little or no heat to the
overburden, thus inhibiting heat losses
in the overburden and improving heater efficiency. Ferromagnetic section 486
includes a ferromagnetic material
such as 409 stainless steel or 410 stainless steel. Ferromagnetic section 486
has a thickness of 0.3 cm. Non-
ferromagnetic section 488 is copper with a thickness of 0.3 cm. Inner
conductor 490 is copper. Inner conductor 490
has a diameter of 0.9 cm. Electrical insulator 500 is silicon nitride, boron
nitride, magnesium oxide powder, or
another suitable insulator material. Electrical insulator 500 has a thickness
of 0.1 cm to 0.3 cm.
FIG. 24 depicts a cross-sectional representation of an embodiment of a
temperature limited heater with an
outer conductor having a ferromagnetic section and a non-ferromagnetic section
placed inside a sheath. FIGS. 25,
26, and 27 depict transverse cross-sectional views of the embodiment shown in
FIG. 24. Ferromagnetic section 486
is 410 stainless steel with a thickness of 0.6 cm. Non-ferromagnetic section
488 is copper with a thickness of 0.6
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cm. Inner conductor 490 is copper with a diameter of 0.9 cm. Outer conductor
502 includes ferromagnetic material.
Outer conductor 502 provides some heat in the overburden section of the
heater. Providing some heat in the
overburden inhibits condensation or refluxing of fluids in the overburden.
Outer conductor 502 is 409, 410, or 446
stainless steel with an outer diameter of 3.0 cm and a thickness of 0.6 cm.
Electrical insulator 500 includes
compacted magnesium oxide powder with a thickness of 0.3 cm. In some
embodiments, electrical insulator 500
includes silicon nitride, boron nitride, or hexagonal type boron nitride.
Conductive section 504 may couple inner
conductor 490 with ferromagnetic section 486 and/or outer conductor 502.
FIG. 28A and FIG. 28B depict cross-sectional representations of an embodiment
of a temperature limited
heater with a ferromagnetic inner conductor. Inner conductor 490 is a 1"
Schedule XXS 446 stainless steel pipe. In
some embodiments, inner conductor 490 includes 409 stainless steel, 410
stainless steel, Invar 36, alloy 42-6, alloy
52, or other ferromagnetic materials. Inner conductor 490 has a diameter of
2.5 cm. Electrical insulator 500
includes compacted silicon nitride, boron nitride, or magnesium oxide powders;
or polymers, Nextel ceramic fiber,
mica, or glass fibers. Outer conductor 502 is copper or any other non-
ferromagnetic material, such as but not limited
to copper alloys, aluminum and/or aluminum alloys. Outer conductor 502 is
coupled to jacket 506. Jacket 506 is
304H, 316H, or 347H stainless steel. In this embodiment, a majority of the
heat is produced in inner conductor 490.
FIG. 29A and FIG. 29B depict cross-sectional representations of an embodiment
of a temperature limited
heater with a ferromagnetic inner conductor and a non-ferromagnetic core.
Inner conductor 490 may be made of 446
stainless steel, 409 stainless steel, 410 stainless steel, carbon steel, Armco
ingot iron, iron-cobalt alloys, or other
ferromagnetic materials. Core 508 may be tightly bonded inside inner conductor
490. Core 508 is copper or other
non-ferromagnetic material. In certain embodiments, core 508 is inserted as a
tight fit inside inner conductor 490
before a drawing operation. In some embodiments, core 508 and inner conductor
490 are coextrusion bonded.
Outer conductor 502 is 347H stainless steel. A drawing or rolling operation to
compact electrical insulator 500 (for
example, compacted silicon nitride, boron nitride, or magnesium oxide powder)
may ensure good electrical contact
between inner conductor 490 and core 508. In this embodiment, heat is produced
primarily in inner conductor 490
until the Curie temperature is approached. Resistance then decreases sharply
as current penetrates core 508.
FIG. 30A and FIG. 30B depict cross-sectional representations of an embodiment
of a temperature limited
heater with a ferromagnetic outer conductor. Inner conductor 490 is nickel-
clad copper. Electrical insulator 500 is
silicon nitride, boron nitride, or magnesium oxide. Outer conductor 502 is a
1" Schedule XXS carbon steel pipe. In
this embodiment, heat is produced primarily in outer conductor 502, resulting
in a small temperature differential
across electrical insulator 500.
FIG. 31A and FIG. 3IB depict cross-sectional representations of an embodiment
of a temperature limited
heater with a ferromagnetic outer conductor that is clad with a corrosion
resistant alloy. Inner conductor 490 is
copper. Outer conductor 502 is a 1" Schedule XXS carbon steel pipe. Outer
conductor 502 is coupled to jacket 506.
Jacket 506 is made of corrosion resistant material (for example, 347H
stainless steel). Jacket 506 provides
protection from corrosive fluids in the wellbore (for example, sulfidizing and
carburizing gases). Heat is produced
primarily in outer conductor 502, resulting in a small temperature
differential across electrical insulator 500.
FIG. 32A and FIG. 32B depict cross-sectional representations of an embodiment
of a temperature limited
heater with a ferromagnetic outer conductor. The outer conductor is clad with
a conductive layer and a corrosion
resistant alloy. Inner conductor 490 is copper. Electrical insulator 500 is
silicon nitride, boron nitride, or
magnesium oxide. Outer conductor 502 is a 1" Schedule 80 446 stainless steel
pipe. Outer conductor 502 is coupled
to jacket 506. Jacket 506 is made from corrosion resistant material such as
347H stainless steel. In an embodiment,
conductive layer 510 is placed between outer conductor 502 and jacket 506.
Conductive layer 510 is a copper layer.
CA 02871784 2014-11-18
Heat is produced primarily in outer conductor 502, resulting in a small
temperature differential across electrical
insulator 500. Conductive layer 510 allows a sharp decrease in the resistance
of outer conductor 502 as the outer
conductor approaches the Curie temperature. Jacket 506 provides protection
from corrosive fluids in the wellbore.
In some embodiments, the conductor (for example, an inner conductor, an outer
conductor, or a
ferromagnetic conductor) is the composite conductor that includes two or more
different materials. In certain
embodiments, the composite conductor includes two or more ferromagnetic
materials. In some embodiments, the
composite ferromagnetic conductor includes two or more radially disposed
materials. In certain embodiments, the
composite conductor includes a ferromagnetic conductor and a non-ferromagnetic
conductor. In some embodiments,
the composite conductor includes the ferromagnetic conductor placed over a non-
ferromagnetic core. Two or more
materials may be used to obtain a relatively flat electrical resistivity
versus temperature profile in a temperature
region below the Curie temperature and/or a sharp decrease (a high turndown
ratio) in the electrical resistivity at or
near the Curie temperature. In some cases, two or more materials are used to
provide more than one Curie
temperature for the temperature limited heater.
The composite electrical conductor may be used as the conductor in any
electrical heater embodiment
described herein. For example, the composite conductor may be used as the
conductor in a conductor-in-conduit
heater or an insulated conductor heater. In certain embodiments, the composite
conductor may be coupled to a
support member such as a support conductor. The support member may be used to
provide support to the composite
conductor so that the composite conductor is not relied upon for strength at
or near the Curie temperature. The
support member may be useful for heaters of lengths of at least 100 m. The
support member may be a non-
ferromagnetic member that has good high temperature creep strength. Examples
of materials that are used for a
support member include, but are not limited to, Haynes 625 alloy and Haynes
HR120 alloy (Haynes
International, Kokomo, Indiana, U.S.A.), NF709, Incoloy 800H alloy and 347HP
alloy (Allegheny Ludlum Corp.,
Pittsburgh, Pennsylvania, U.S.A.). In some embodiments, materials in a
composite conductor are directly coupled
(for example, brazed, metallurgically bonded, or swaged) to each other and/or
the support member. Using a support
member may reduce the need for the ferromagnetic member to provide support for
the temperature limited heater,
especially at or near the Curie temperature. Thus, the temperature limited
heater may be designed with more
flexibility in the selection of ferromagnetic materials.
= FIG. 33 depicts a cross-sectional representation of an embodiment of the
composite conductor with the
support member. Core 508 is surrounded by ferromagnetic conductor 512 and
support member 514. In some
embodiments, core 508, ferromagnetic conductor 512, and support member 514 are
directly coupled (for example,
brazed together or metallurgically bonded together). In one embodiment, core
508 is copper, ferromagnetic
conductor 512 is 446 stainless steel, and support member 514 is 347H alloy. In
certain embodiments, support
member 514 is a Schedule 80 pipe. Support member 514 surrounds the composite
conductor having ferromagnetic
conductor 512 and core 508. Ferromagnetic conductor 512 and core 508 may be
joined to form the composite
conductor by, for example, a coextrusion process. For example, the composite
conductor is a 1.9 cm outside
diameter 446 stainless steel ferromagnetic conductor surrounding a 0.95 cm
diameter copper core.
In certain embodiments, the diameter of core 508 is adjusted relative to a
constant outside diameter of
ferromagnetic conductor 512 to adjust the turndown ratio of the temperature
limited heater. For example, the
diameter of core 508 may be increased to 1.14 cm while maintaining the outside
diameter of ferromagnetic
conductor 512 at 1.9 cm to increase the turndown ratio of the heater.
In some embodiments, conductors (for example, core 508 and ferromagnetic
conductor 512) in the
composite conductor are separated by support member 514. FIG. 34 depicts a
cross-sectional representation of an
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CA 02871784 2014-11-18
embodiment of the composite conductor with support member 514 separating the
conductors. In one embodiment,
core 508 is copper with a diameter of 0.95 cm, support member 514 is 347H
alloy with an outside diameter of 1.9
cm, and ferromagnetic conductor 512 is 446 stainless steel with an outside
diameter of 2.7 cm. The support member
depicted in FIG. 34 has a lower creep strength relative to the support members
depicted in FIG. 33.
In certain embodiments, support member 514 is located inside the composite
conductor. FIG. 35 depicts a
cross-sectional representation of an embodiment of the composite conductor
surrounding support member 514.
Support member 514 is made of 347H alloy. Inner conductor 490 is copper.
Ferromagnetic conductor 512 is 446
stainless steel. In one embodiment, support member 514 is 1.25 cm diameter
347H alloy, inner conductor 490 is 1.9
cm outside diameter copper, and ferromagnetic conductor 512 is 2.7 cm outside
diameter 446 stainless steel. The
turndown ratio is higher than the turndown ratio for the embodiments depicted
in FIGS. 33, 34, and 36 for the same
outside diameter, but the creep strength is lower.
In some embodiments, the thickness of inner conductor 490, which is copper, is
reduced and the thickness
of support member 514 is increased to increase the creep strength at the
expense of reduced turndown ratio. For
example, the diameter of support member 514 is increased to 1.6 cm while
maintaining the outside diameter of inner
conductor 490 at 1.9 cm to reduce the thickness of the conduit. This reduction
in thickness of inner conductor 490
results in a decreased turndown ratio relative to the thicker inner conductor
embodiment but an increased creep
strength.
In one embodiment, support member 514 is a conduit (or pipe) inside inner
conductor 490 and
ferromagnetic conductor 512. FIG. 36 depicts a cross-sectional representation
of an embodiment of the composite
conductor surrounding support member 514. In one embodiment, support member
514 is 347H alloy with a 0.63 cm
diameter center hole. In some embodiments, support member 514 is a preformed
conduit. In certain embodiments,
support member 514 is formed by having a dissolvable material (for example,
copper dissolvable by nitric acid)
located inside the support member during formation of the composite conductor.
The dissolvable material is
dissolved to form the hole after the conductor is assembled. In an embodiment,
support member 514 is 347H alloy
with an inside diameter of 0.63 cm and an outside diameter of 1.6 cm, inner
conductor 490 is copper with an outside
diameter of 1.8 cm, and ferromagnetic conductor 512 is 446 stainless steel
with an outside diameter of 2.7 cm.
In certain embodiments, the composite electrical conductor is used as the
conductor in the conductor-in-
conduit heater. For example, the composite electrical conductor may be used as
conductor 516 in FIG. 37
FIG. 37 depicts a cross-sectional representation of an embodiment of the
conductor-in-conduit heater.
Conductor 516 is disposed in conduit 518. Conductor 516 is a rod or conduit of
electrically conductive material.
Low resistance sections 520 are present at both ends of conductor 516 to
generate less heating in these sections.
Low resistance section 520 is formed by having a greater cross-sectional area
of conductor 516 in that section, or the
sections are made of material having less resistance. In certain embodiments,
low resistance section 520 includes a
low resistance conductor coupled to conductor 516.
Conduit 518 is made of an electrically conductive material. Conduit 518 is
disposed in opening 522 in
hydrocarbon layer 460. Opening 522 has a diameter that accommodates conduit
518.
Conductor 516 may be centered in conduit 518 by centralizers 524. Centralizers
524 electrically isolate
conductor 516 from conduit 518. Centralizers 524 inhibit movement and properly
locate conductor 516 in conduit
518. Centralizers 524 are made of ceramic material or a combination of ceramic
and metallic materials. Centralizers
524 inhibit deformation of conductor 516 in conduit 518. Centralizers 524 are
touching or spaced at intervals
between approximately 0.1 m (meters) and approximately 3 m or more along
conductor 516.
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A second low resistance section 520 of conductor 516 may couple conductor 516
to wellhead 450, as
depicted in FIG. 37. Electrical current may be applied to conductor 516 from
power cable 526 through low
resistance section 520 of conductor 516. Electrical current passes from
conductor 516 through sliding connector 528
to conduit 518. Conduit 518 may be electrically insulated from overburden
casing 530 and from wellhead 450 to
return electrical current to power cable 526. Heat may be generated in
conductor 516 and conduit 518. The
generated heat may radiate in conduit 518 and opening 522 to heat at least a
portion of hydrocarbon layer 460.
Overburden casing 530 may be disposed in overburden 458. Overburden casing 530
is, in some
embodiments, surrounded by materials (for example, reinforcing material and/or
cement) that inhibit heating of
overburden 458. Low resistance section 520 of conductor 516 may be placed in
overburden casing 530. Low
resistance section 520 of conductor 516 is made of, for example, carbon steel.
Low resistance section 520 of
conductor 516 may be centralized in overburden casing 530 using centralizers
524. Centralizers 524 are spaced at
intervals of approximately 6 m to approximately 12 m or, for example,
approximately 9 m along low resistance
section 520 of conductor 516. In a heater embodiment, low resistance section
520 of conductor 516 is coupled to
conductor 516 by one or more welds. In other heater embodiments, low
resistance sections are threaded, threaded
and welded, or otherwise coupled to the conductor. Low resistance section 520
generates little or no heat in
overburden casing 530. Packing 532 may be placed between overburden casing 530
and opening 522. Packing 532
may be used as a cap at the junction of overburden 458 and hydrocarbon layer
460 to allow filling of materials in the
annulus between overburden casing 530 and opening 522. In some embodiments,
packing 532 inhibits fluid from
flowing from opening 522 to surface 534.
FIG. 38 depicts a cross-sectional representation of an embodiment of a
removable conductor-in-conduit
heat source. Conduit 518 may be placed in opening 522 through overburden 458
such that a gap remains between
the conduit and overburden casing 530. Fluids may be removed from opening 522
through the gap between conduit
518 and overburden casing 530. Fluids may be removed from the gap through
conduit 536. Conduit 518 and
components of the heat source included in the conduit that are coupled to
wellhead 450 may be removed from
opening 522 as a single unit. The heat source may be removed as a single unit
to be repaired, replaced, and/or used
in another portion of the formation.
For a temperature limited heater in which the ferromagnetic conductor provides
a majority of the resistive
heat output below the Curie temperature, a majority of the current flows
through material with highly non-linear
functions of magnetic field (H) versus magnetic induction (B). These non-
linear functions may cause strong
inductive effects and distortion that lead to decreased power factor in the
temperature limited heater at temperatures
below the Curie temperature. These effects may render the electrical power
supply to the temperature limited heater
difficult to control and may result in additional current flow through surface
and/or overburden power supply
conductors. Expensive and/or difficult to implement control systems such as
variable capacitors or modulated power
supplies may be used to compensate for these effects and to control
temperature limited heaters where the majority
of the resistive heat output is provided by current flow through the
ferromagnetic material.
In certain temperature limited heater embodiments, the ferromagnetic conductor
confines a majority of the
flow of electrical current to an electrical conductor coupled to the
ferromagnetic conductor when the temperature
limited heater is below or near the Curie temperature of the ferromagnetic
conductor. The electrical conductor may
be a sheath, jacket, support member, corrosion resistant member, or other
electrically resistive member. In some
embodiments, the ferromagnetic conductor confines a majority of the flow of
electrical current to the electrical
conductor positioned between an outermost layer and the ferromagnetic
conductor. The ferromagnetic conductor is
located in the cross section of the temperature limited heater such that the
magnetic properties of the ferromagnetic
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conductor at or below the Curie temperature of the ferromagnetic conductor
confine the majority of the flow of
electrical current to the electrical conductor. The majority of the flow of
electrical current is confined to the
electrical conductor due to the skin effect of the ferromagnetic conductor.
Thus, the majority of the current is
flowing through material with substantially linear resistive properties
throughout most of the operating range of the
heater.
In certain embodiments, the ferromagnetic conductor and the electrical
conductor are located in the cross
section of the temperature limited heater so that the skin effect of the
ferromagnetic material limits the penetration
depth of electrical current in the electrical conductor and the ferromagnetic
conductor at temperatures below the
Curie temperature of the ferromagnetic conductor. Thus, the electrical
conductor provides a majority of the
electrically resistive heat output of the temperature limited heater at
temperatures up to a temperature at or near the
Curie temperature of the ferromagnetic conductor. In certain embodiments, the
dimensions of the electrical
conductor may be chosen to provide desired heat output characteristics.
Because the majority of the current flows through the electrical conductor
below the Curie temperature, the
temperature limited heater has a resistance versus temperature profile that at
least partially reflects the resistance
versus temperature profile of the material in the electrical conductor. Thus,
the resistance versus temperature profile
of the temperature limited heater is substantially linear below the Curie
temperature of the ferromagnetic conductor
if the material in the electrical conductor has a substantially linear
resistance versus temperature profile. For
example, the temperature limited heater in which the majority of the current
flows in the electrical conductor below
the Curie temperature may have a resistance versus temperature profile similar
to the profile shown in FIG. 162.
The resistance of the temperature limited heater has little or no dependence
on the current flowing through the heater
until the temperature nears the Curie temperature. The majority of the current
flows in the electrical conductor
rather than the ferromagnetic conductor below the Curie temperature.
Resistance versus temperature profiles for temperature limited heaters in
which the majority of the current
flows in the electrical conductor also tend to exhibit sharper reductions in
resistance near or at the Curie temperature
of the ferromagnetic conductor. For example, the reduction in resistance shown
in FIG. 162 is sharper than the
reduction in resistance shown in FIG. 148. The sharper reductions in
resistance near or at the Curie temperature are
easier to control than more gradual resistance reductions near the Curie
temperature.
In certain embodiments, the material and/or the dimensions of the material in
the electrical conductor are
selected so that the temperature limited heater has a desired resistance
versus temperature profile below the Curie
temperature of the ferromagnetic conductor.
Temperature limited heaters in which the majority of the current flows in the
electrical conductor rather
than the ferromagnetic conductor below the Curie temperature are easier to
predict and/or control. Behavior of
temperature limited heaters in which the majority of the current flows in the
electrical conductor rather than the
ferromagnetic conductor below the Curie temperature may be predicted by, for
example, its resistance versus
temperature profile and/or its power factor versus temperature profile.
Resistance versus temperature profiles and/or
power factor versus temperature profiles may be assessed or predicted by, for
example, experimental measurements
that assess the behavior of the temperature limited heater, analytical
equations that assess or predict the behavior of
the temperature limited heater, and/or simulations that assess or predict the
behavior of the temperature limited
heater.
In certain embodiments, assessed or predicted behavior of the temperature
limited heater is used to control
the temperature limited heater. The temperature limited heater may be
controlled based on measurements
(assessments) of the resistance and/or the power factor during operation of
the heater. In some embodiments, the
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power, or current, supplied to the temperature limited heater is controlled
based on assessment of the resistance
and/or the power factor of the heater during operation of the heater and the
comparison of this assessment versus the
predicted behavior of the heater. In certain embodiments, the temperature
limited heater is controlled without
measurement of the temperature of the heater or a temperature near the heater.
Controlling the temperature limited
heater without temperature measurement eliminates operating costs associated
with downhole temperature
measurement. Controlling the temperature limited heater based on assessment of
the resistance and/or the power
factor of the heater also reduces the time for making adjustments in the power
or current supplied to the heater
compared to controlling the heater based on measured temperature.
As the temperature of the temperature limited heater approaches or exceeds the
Curie temperature of the
ferromagnetic conductor, reduction in the ferromagnetic properties of the
ferromagnetic conductor allows electrical
current to flow through a greater portion of the electrically conducting cross
section of the temperature limited
heater. Thus, the electrical resistance of the temperature limited heater is
reduced and the temperature limited heater
automatically provides reduced heat output at or near the Curie temperature of
the ferromagnetic conductor. In
certain embodiments, a highly electrically conductive member is coupled to the
ferromagnetic conductor and the
electrical conductor to reduce the electrical resistance of the temperature
limited heater at or above the Curie
temperature of the ferromagnetic conductor. The highly electrically conductive
member may be an inner conductor,
a core, or another conductive member of copper, aluminum, nickel, or alloys
thereof.
The ferromagnetic conductor that confines the majority of the flow of
electrical current to the electrical
conductor at temperatures below the Curie temperature may have a relatively
small cross section compared to the
ferromagnetic conductor in temperature limited heaters that use the
ferromagnetic conductor to provide the majority
of resistive heat output up to or near the Curie temperature. A temperature
limited heater that uses the electrical
conductor to provide a majority of the resistive heat output below the Curie
temperature has low magnetic
inductance at temperatures below the Curie temperature because less current is
flowing through the ferromagnetic
conductor as compared to the temperature limited heater where the majority of
the resistive heat output below the
Curie temperature is provided by the ferromagnetic material. Magnetic field
(H) at radius (r) of the ferromagnetic
conductor is proportional to the current (I) flowing through the ferromagnetic
conductor and the core divided by the
radius, or:
(5) H oc 1/r.
Since only a portion of the current flows through the ferromagnetic conductor
for a temperature limited heater that
uses the outer conductor to provide a majority of the resistive heat output
below the Curie temperature, the magnetic
field of the temperature limited heater may be significantly smaller than the
magnetic field of the temperature limited
heater where the majority of the current flows through the ferromagnetic
material. The relative magnetic
permeability (p.) may be large for small magnetic fields.
The skin depth (8) of the ferromagnetic conductor is inversely proportional to
the square root of the relative
magnetic permeability ( ):
(6) oc (1/ ).
Increasing the relative magnetic permeability decreases the skin depth of the
ferromagnetic conductor. However,
because only a portion of the current flows through the ferromagnetic
conductor for temperatures below the Curie
temperature, the radius (or thickness) of the ferromagnetic conductor may be
decreased for ferromagnetic materials
with large relative magnetic permeabihties to compensate for the decreased
skin depth while still allowing the skin
effect to limit the penetration depth of the electrical current to the
electrical conductor at temperatures below the
Curie temperature of the ferromagnetic conductor. The radius (thickness) of
the ferromagnetic conductor may be
CA 02871784 2014-11-18
between 0.3 mm and 8 mm, between 0.3 mm and 2 mm, or between 2 mm and 4 mm
depending on the relative
magnetic permeability of the ferromagnetic conductor. Decreasing the thickness
of the ferromagnetic conductor
decreases costs of manufacturing the temperature limited heater, as the cost
of ferromagnetic material tends to be a
significant portion of the cost of the temperature limited heater. Increasing
the relative magnetic permeability of the
ferromagnetic conductor provides a higher turndown ratio and a sharper
decrease in electrical resistance for the
temperature limited heater at or near the Curie temperature of the
ferromagnetic conductor.
Ferromagnetic materials (such as purified iron or iron-cobalt alloys) with
high relative magnetic
permeabilities (for example, at least 200, at least 1000, at least I x l0, or
at least 1 x 105) and/or high Curie
temperatures (for example, at least 600 C, at least 700 C, or at least 800
C) tend to have less corrosion resistance
ancUor less mechanical strength at high temperatures. The electrical conductor
may provide corrosion resistance
and/or high mechanical strength at high temperatures for the temperature
limited heater. Thus, the ferromagnetic
conductor may be chosen primarily for its ferromagnetic properties.
Confining the majority of the flow of electrical current to the electrical
conductor below the Curie
temperature of the ferromagnetic conductor reduces variations in the power
factor. Because only a portion of the
electrical current flows through the ferromagnetic conductor below the Curie
temperature, the non-linear
ferromagnetic properties of the ferromagnetic conductor have little or no
effect on the power factor of the
temperature limited heater, except at or near the Curie temperature. Even at
or near the Curie temperature, the effect
on the power factor is reduced compared to temperature limited heaters in
which the ferromagnetic conductor
provides a majority of the resistive heat output below the Curie temperature.
Thus, there is less or no need for
external compensation (for example, variable capacitors or waveform
modification) to adjust for changes in the
inductive load of the temperature limited heater to maintain a relatively high
power factor.
In certain embodiments, the temperature limited heater, which confines the
majority of the flow of electrical
current to the electrical conductor below the Curie temperature of the
ferromagnetic conductor, maintains the power
factor above 0.85, above 0.9, or above 0.95 during use of the heater. Any
reduction in the power factor occurs only
in sections of the temperature limited heater at temperatures near the Curie
temperature. Most sections of the
temperature limited heater are typically not at or near the Curie temperature
during use. These sections have a high
power factor that approaches 1Ø The power factor for the entire temperature
limited heater is maintained above
0.85, above 0.9, or above 0.95 during use of the heater even if some sections
of the heater have power factors below
0.85.
Maintaining high power factors allows for less expensive power supplies and/or
control devices such as
solid state power supplies or SCRs (silicon controlled rectifiers). These
devices may fail to operate properly if the
power factor varies by too large an amount because of inductive loads. With
the power factors maintained at high
values; however, these devices may be used to provide power to the temperature
limited heater. Solid state power
supplies have the advantage of allowing fine tuning and controlled adjustment
of the power supplied to the
temperature limited heater.
In some embodiments, transformers are used to provide power to the temperature
limited heater. Multiple
voltage taps may be made into the transformer to provide power to the
temperature limited heater. Multiple voltage
taps allows the current supplied to switch back and forth between the multiple
voltages. This maintains the current
within a range bound by the multiple voltage taps.
The highly electrically conductive member, or inner conductor, increases the
turndown ratio of the
temperature limited heater. In certain embodiments, thickness of the highly
electrically conductive member is
increased to increase the turndown ratio of the temperature limited heater. In
some embodiments, the thickness of
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the electrical conductor is reduced to increase the turndown ratio of the
temperature limited heater. In certain
embodiments, the turndown ratio of the temperature limited heater is between
1.1 and 10, between 2 and 8, or
between 3 and 6 (for example, the turndown ratio is at least 1.1, at least 2,
or at least 3).
FIG. 39 depicts an embodiment of a temperature limited heater in which the
support member provides a
majority of the heat output below the Curie temperature of the ferromagnetic
conductor. Core 508 is an inner
conductor of the temperature limited heater. In certain embodiments, core 508
is a highly electrically conductive
material such as copper or aluminum. In some embodiments, core 508 is a copper
alloy that provides mechanical
strength and good electrically conductivity such as a dispersion strengthened
copper. In one embodiment, core 508
is Glidcop (SCM Metal Products, Inc., Research Triangle Park, North Carolina,
U.S.A.). Ferromagnetic conductor
512 is a thin layer of ferromagnetic material between electrical conductor 538
and core 508. In certain
embodiments, electrical conductor 538 is also support member 514. In certain
embodiments, ferromagnetic
conductor 512 is iron or an iron alloy. In some embodiments, ferromagnetic
conductor 512 includes ferromagnetic
material with a high relative magnetic permeability. For example,
ferromagnetic conductor 512 may be purified iron
such as Armco ingot iron (AK Steel Ltd., United Kingdom). Iron with some
impurities typically has a relative
magnetic permeability on the order of 400. Purifying the iron by annealing the
iron in hydrogen gas (H2) at 1450 C
increases the relative magnetic permeability of the iron. Increasing the
relative magnetic permeability of
ferromagnetic conductor 512 allows the thickness of the ferromagnetic
conductor to be reduced. For example, the
thickness of unpurified iron may be approximately 4.5 mm while the thickness
of the purified iron is approximately
0.76 mm.
In certain embodiments, electrical conductor 538 provides support for
ferromagnetic conductor 512 and the
temperature limited heater. Electrical conductor 538 may be made of a material
that provides good mechanical
strength at temperatures near or above the Curie temperature of ferromagnetic
conductor 512. In certain
embodiments, electrical conductor 538 is a corrosion resistant member.
Electrical conductor 538 (support member
514) may provide support for ferromagnetic conductor 512 and corrosion
resistance. Electrical conductor 538 is
made from a material that provides desired electrically resistive heat output
at temperatures up to and/or above the
Curie temperature of ferromagnetic conductor 512.
In an embodiment, electrical conductor 538 is 347H stainless steel. In some
embodiments, electrical
conductor 538 is another electrically conductive, good mechanical strength,
corrosion resistant material. For
example, electrical conductor 538 may be 304H, 316H, 347HH, NF709, Incoloy
800H alloy (Inco Alloys
International, Huntington, West Virginia, U.S.A.), Haynes HRI2O alloy, or
Inconel 617 alloy.
In some embodiments, electrical conductor 538 (support member 514) includes
different alloys in different
portions of the temperature limited heater. For example, a lower portion of
electrical conductor 538 (support
member 514) is 347H stainless steel and an upper portion of the electrical
conductor (support member) is NF709. In
certain embodiments, different alloys are used in different portions of the
electrical conductor (support member) to
increase the mechanical strength of the electrical conductor (support member)
while maintaining desired heating
properties for the temperature limited heater.
In some embodiments, ferromagnetic conductor 512 includes different
ferromagnetic conductors in
different portions of the temperature limited heater. Different ferromagnetic
conductors may be used in different
portions of the temperature limited heater to vary the Curie temperature and,
thus, the maximum operating
temperature in the different portions. In some embodiments, the Curie
temperature in an upper portion of the
temperature limited heater is lower than the Curie temperature in a lower
portion of the heater. The lower Curie
temperature in the upper portion increases the creep-rupture strength lifetime
in the upper portion of the heater.
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In the embodiment depicted in FIG. 39, ferromagnetic conductor 512, electrical
conductor 538, and core
508 are dimensioned so that the skin depth of the ferromagnetic conductor
limits the penetration depth of the
majority of the flow of electrical current to the support member when the
temperature is below the Curie temperature
of the ferromagnetic conductor. Thus, electrical conductor 538 provides a
majority of the electrically resistive heat
output of the temperature limited heater at temperatures up to a temperature
at or near the Curie temperature of
ferromagnetic conductor 512. In certain embodiments, the temperature limited
heater depicted in FIG. 39 is smaller
(for example, an outside diameter of 3 cm, 2.9 cm, 2.5 cm, or less) than other
temperature limited heaters that do not
use electrical conductor 538 to provide the majority of electrically resistive
heat output. The temperature limited
heater depicted in FIG. 39 may be smaller because ferromagnetic conductor 512
is thin as compared to the size of
the ferromagnetic conductor needed for a temperature limited heater in which
the majority of the resistive heat
output is provided by the ferromagnetic conductor.
In some embodiments, the support member and the corrosion resistant member are
different members in the
temperature limited heater. FIGS. 40 and 41 depict embodiments of temperature
limited heaters in which the jacket
provides a majority of the heat output below the Curie temperature of the
ferromagnetic conductor. In these
embodiments, electrical conductor 538 is jacket 506. Electrical conductor 538,
ferromagnetic conductor 512,
support member 514, and core 508 (in FIG. 40) or inner conductor 490 (in FIG.
41) are dimensioned so that the skin
depth of the ferromagnetic conductor limits the penetration depth of the
majority of the flow of electrical current to
the thickness of the jacket. In certain embodiments, electrical conductor 538
is a material that is corrosion resistant
and provides electrically resistive heat output below the Curie temperature of
ferromagnetic conductor 512. For
example, electrical conductor 538 is 825 stainless steel or 347H stainless
steel. In some embodiments, electrical
conductor 538 has a small thickness (for example, on the order of 0.5 mm).
In FIG. 40, core 508 is highly electrically conductive material such as copper
or aluminum. Support
member 514 is 347H stainless steel or another material with good mechanical
strength at or near the Curie
temperature of ferromagnetic conductor 512.
In FIG. 41, support member 514 is the core of the temperature limited heater
and is 347H stainless steel or
another material with good mechanical strength at or near the Curie
temperature of ferromagnetic conductor 512.
Inner conductor 490 is highly electrically conductive material such as copper
or aluminum.
In certain embodiments, the materials and design of the temperature limited
heater are chosen to allow use
of the heater at high temperatures (for example, above 850 C). FIG. 42
depicts a high temperature embodiment of
the temperature limited heater. The heater depicted in FIG. 42 operates as a
conductor-in-conduit heater with the
majority of heat being generated in conduit 518. The conductor-in-conduit
heater may provide a higher heat output
because the majority of heat is generated in conduit 518 rather than conductor
516. Having the heat generated in
conduit 518 reduces heat losses associated with transferring heat between the
conduit and conductor 516.
Core 508 and conductive layer 510 are copper. In some embodiments, core 508
and conductive layer 510
are nickel if the operating temperatures is to be near or above the melting
point of copper. Support members 514 are
electrically conductive materials with good mechanical strength at high
temperatures. Materials for support
members 514 that withstand at least a maximum temperature of about 870 C may
be, but are not limited to, MO-
RE alloys (Duraloy Technologies, Inc. (Scottdale, Pennsylvania, U.S.A.)),
CF8C+ (Metaltek Intl. (Waukesha,
Wisconsin, U.S.A.)), or Inconel 617 alloy. Materials for support members 514
that withstand at least a maximum
temperature of about 980 C include, but are not limited to, Incoloy Alloy MA
956. Support member 514 in
conduit 518 provides mechanical support for the conduit. Support member 514 in
conductor 516 provides
mechanical support for core 508.
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Electrical conductor 538 is a thin corrosion resistant material. In certain
embodiments, electrical conductor
538 is 347H, 617, 625, or 800H stainless steel. Ferromagnetic conductor 512 is
a high Curie temperature
ferromagnetic material such as iron-cobalt alloy (for example, a 15% by weight
cobalt, iron-cobalt alloy).
In certain embodiments, electrical conductor 538 provides the majority of heat
output of the temperature
limited heater at temperatures up to a temperature at or near the Curie
temperature of ferromagnetic conductor 512.
Conductive layer 510 increases the turndown ratio of the temperature limited
heater.
For long vertical temperature limited heaters (for example, heaters at least
300 m, at least 500 m, or at least
1 km in length), the hanging stress becomes important in the selection of
materials for the temperature limited heater.
Without the proper selection of material, the support member may not have
sufficient mechanical strength (for
example, creep-rupture strength) to support the weight of the temperature
limited heater at the operating
temperatures of the heater. FIG. 43 depicts hanging stress (ksi (kilopounds
per square inch)) versus outside diameter
(in.) for the temperature limited heater shown in FIG. 39 with 347H as the
support member. The hanging stress was
assessed with the support member outside a 0.5" copper core and a 0.75"
outside diameter carbon steel
ferromagnetic conductor. This assessment assumes the support member bears the
entire load of the heater and that
the heater length is 1000 ft. (about 305 m). As shown in FIG. 43, increasing
the thickness of the support member
decreases the hanging stress on the support member. Decreasing the hanging
stress on the support member allows
the temperature limited heater to operate at higher temperatures.
In certain embodiments, materials for the support member are varied to
increase the maximum allowable
hanging stress at operating temperatures of the temperature limited heater
and, thus, increase the maximum operating
temperature of the temperature limited heater. Altering the materials of the
support member affects the heat output
of the temperature limited heater below the Curie temperature because changing
the materials changes the resistance
versus temperature profile of the support member. In certain embodiments, the
support member is made of more
than one material along the length of the heater so that the temperature
limited heater maintains desired operating
properties (for example, resistance versus temperature profile below the Curie
temperature) as much as possible
while providing sufficient mechanical properties to support the heater.
FIG. 44 depicts hanging stress (ksi) versus temperature ( F) for several
materials and varying outside
diameters for the temperature limited heaters. Curve 540 is for 347H stainless
steel. Curve 542 is for Incoloy alloy
800H. Curve 544 is for Haynes HR120 alloy. Curve 546 is for NF709. Each of
the curves includes four points
that represent various outside diameters of the support member. The point with
the highest stress for each curve
corresponds to outside diameter of 1.05". The point with the second highest
stress for each curve corresponds to
outside diameter of 1.15". The point with the second lowest stress for each
curve corresponds to outside diameter of
1.25". The point with the lowest stress for each curve corresponds to outside
diameter of 1.315". As shown in FIG.
44, increasing the strength and/or outside diameter of the material and the
support member increases the maximum
operating temperature of the temperature limited heater.
FIGS. 45, 46, 47, and 48 depict examples of embodiments for temperature
limited heaters able to provide
desired heat output and mechanical strength for operating temperatures up to
about 770 C for 30,000 hrs. creep-
rupture lifetime. The depicted temperature limited heaters have lengths of
1000 ft, copper cores of 0.5" diameter,
and iron ferromagnetic conductors with outside diameters of 0.765". In FIG.
45, the support member in heater
portion 548 is 347H stainless steel. The support member in heater portion 550
is Incoloy alloy 800H. Portion 548
has a length of 750 ft. and portion 550 has a length of 250 ft. The outside
diameter of the support member is 1.315".
In FIG. 46, the support member in heater portion 548 is 347H stainless steel.
The support member in heater portion
550 is Incoloy alloy 800H. The support member in heater portion 552 is Haynes
HR120 alloy. Portion 548 has a
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length of 650 ft., portion 550 has a length of 300 ft., and portion 552 has a
length of 50 ft. The outside diameter of
the support member is 1.15". In FIG. 47, the support member in heater portion
548 is 347H stainless steel. The
support member in heater portion 550 is lncoloy alloy 800H. The support
member in heater portion 552 is Haynes
HR120 alloy. Portion 548 has a length of 550 ft., portion 550 has a length of
250 ft., and portion 552 has a length
of 200 ft. The outside diameter of the support member is 1.05".
In some embodiments, a transition section is used between sections of the
heater. For example, if one or
more portions of the heater have varying Curie temperatures, a transition
section may be used between portions to
provide strength that compensates for the differences in temperatures in the
portions. FIG. 48 depicts another
example of an embodiment of a temperature limited heater able to provide
desired heat output and mechanical
strength. The support member in heater portion 548 is 347H stainless steel.
The support member in heater portion
550 is NF709. The support member in heater portion 552 is 347H. Portion 548
has a length of 550 ft. and a Curie
temperature of 843 C, portion 550 has a length of 250 ft. and a Curie
temperature of 843 C, and portion 552 has a
length of 180 ft. and a Curie temperature of 770 C. Transition section 554
has a length of 20 ft., a Curie
temperature of 770 C, and the support member is NF709.
The materials of the support member along the length of the temperature
limited heater may be varied to
achieve a variety of desired operating properties. The choice of the materials
of the temperature limited heater is
adjusted depending on a desired use of the temperature limited heater. TABLE 1
lists examples of materials that
may be used for the support member. The table provides the hanging stresses
(a) of the support members and the
maximum operating temperatures of the temperature limited heaters for several
different outside diameters (OD) of
the support member. The core diameter and the outside diameter of the iron
ferromagnetic conductor in each case
are 0.5" and 0.765", respectively.
TABLE 1
Material OD = 1.05" OD = 1.15" OD = 1.25" OD =
1.315"
a (ksi) T ( F) a (ksi) T ( F) a (ksi)
T ( F) a (ksi) T ( F)
347H stainless steel 7.55 1310 6.33 1340 5.63 1360
5.31 1370
Incoloy alloy 800H 7.55 1337 6.33 1378 5.63 1400
5.31 1420
Haynes H R120 7.57 1450 6.36 1492 5.65 1520
5.34 1540
alloy
HA230 7.91 1475 6.69 1510 5.99 1530
5.67 1540
Haynes alloy 556 7.65 1458 6.43 1492 5.72 1512
5.41 1520
NF709 7.57 1440 6.36 1480 5.65 1502
5.34 1512
In certain embodiments, one or more portions of the temperature limited heater
have varying outside
diameters and/or materials to provide desired properties for the heater. FIGS.
49 and 50 depict examples of
embodiments for temperature limited heaters that vary the diameter and/or
materials of the support member along
the length of the heaters to provide desired operating properties and
sufficient mechanical properties (for example,
creep-rupture strength properties) for operating temperatures up to about 834
C for 30,000 hrs., heater lengths of
850 ft, a copper core diameter of 0.5", and an iron-cobalt (6% by weight
cobalt) ferromagnetic conductor outside
diameter of 0.75". In FIG. 49, portion 548 is 347H stainless steel with a
length of 300 ft and an outside diameter of
1.15". Portion 550 is NF709 with a length of 400 ft and an outside diameter of
1.15". Portion 552 is NF709 with a
length of 150 ft and an outside diameter of 1.25". In FIG. 50, portion 548 is
3471-1 stainless steel with a length of
300 ft and an outside diameter of 1.15". Portion 550 is 347H stainless steel
with a length of 100 ft and an outside
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diameter of 1.20". Portion 552 is NF709 with a length of 350 ft and an outside
diameter of 1.20". Portion 556 is
NF709 with a length of 100 ft and an outside diameter of 1.25".
In certain embodiments, one or more portions of the temperature limited heater
have varying dimensions
and/or varying materials to provide different power outputs along the length
of the heater. More or less power
output may be provided by varying the selected temperature (for example, the
Curie temperature) of the temperature
limited heater by using different ferromagnetic materials along its length
and/or by varying the electrical resistance
of the heater by using different dimensions in the heat generating member
along the length of the heater. Different
power outputs along the length of the temperature limited heater may be needed
to compensate for different thermal
properties in the formation adjacent to the heater. For example, an oil shale
formation may have different water-
filled porosities, dawsonite compositions, and/or nahcolite compositions at
different depths in the formation.
Portions of the formation with higher water-filled porosities, higher
dawsonite compositions, and/or higher nahcolite
compositions may need more power input than portions with lower water-filled
porosities, lower dawsonite
compositions, and/or lower nahcolite compositions to achieve a similar heating
rate. Power output may be varied
along the length of the heater so that the portions of the formation with
different properties (such as water-filled
porosities, dawsonite compositions, and/or nahcolite compositions) are heated
at approximately the same heating
rate.
In certain embodiments, portions of the temperature limited heater have
different selected self-limiting
temperatures (for example, Curie temperatures), materials, and/or dimensions
to compensate for varying thermal
properties of the formation along the length of the heater. For example, Curie
temperatures, support member
materials, and/or dimensions of the portions of the heaters depicted in FIGS.
45-50 may be varied to provide varying
power outputs and/or operating temperatures along the length of the heater.
As one example, in an embodiment of the temperature limited heater depicted in
FIG. 45, portion 550 may
be used to heat portions of the formation that, on average, have higher water-
filled porosities, dawsonite
compositions, and/or nahcolite compositions than portions of the formation
heated by portion 548. Portion 550 may
provide less power output than portion 548 to compensate for the differing
thermal properties of the different
portions of the formation so that the entire formation is heated at an
approximately constant heating rate. Portion
550 may require less power output because, for example, portion 550 is used to
heat portions of the formation with
low water-filled porosities and/or little or no dawsonite. In one embodiment,
portion 550 has a Curie temperature of
770 C (pure iron) and portion 548 has a Curie temperature of 843 C (iron
with added cobalt). Such an
embodiment may provide more power output from portion 548 so that the
temperature lag between the two portions
is reduced. Adjusting the Curie temperature of portions of the heater adjusts
the selected temperature at which the
heater self-limits. In some embodiments, the dimensions of portion 550 are
adjusted to further reduce the
temperature lag so that the formation is heated at an approximately constant
heating rate throughout the formation.
Dimensions of the heater may be adjusted to adjust the heating rate of one or
more portions of the heater. For
example, the thickness of an outer conductor in portion 550 may be increased
relative to the ferromagnetic member
and/or the core of the heater so that the portion has a higher electrical
resistance and the portion provides a higher
power output below the Curie temperature of the portion.
Reducing the temperature lag between different portions of the formation may
reduce the overall time
needed to bring the formation to a desired temperature. Reducing the time
needed to bring the formation to the
desired temperature reduces heating costs and produces desirable production
fluids more quickly.
Temperature limited heaters with varying Curie temperatures may also have
varying support member
materials to provide mechanical strength for the heater (for example, to
compensate for hanging stress of the heater
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and/or provide sufficient creep-rupture strength properties). For example, in
the embodiment of the temperature
limited heater depicted in FIG. 48, portions 548 and 550 have a Curie
temperature of 843 C. Portion 548 has a
support member made of 347H stainless steel. Portion 550 has a support member
made of NF709. Portion 552 has
a Curie temperature of 770 C and a support member made of 347H stainless
steel. Transition section 554 has a
Curie temperature of 770 C and a support member made of NF709. Transition
section 554 may be short in length
compared to portions 548, 550, and 552. Transition section 554 may be placed
between portions 550 and 552 to
compensate for the temperature and material differences between the portions.
For example, transition section 554
may be used to compensate for differences in creep properties between portions
550 and 552.
Such a substantially vertical temperature limited heater may have less
expensive, lower strength materials
in portion 552 because of the lower Curie temperature in this portion of the
heater. For example, 347H stainless
steel may be used for the support member because of the lower maximum
operating temperature of portion 552 as
compared to portion 550. Portion 550 may require more expensive, higher
strength material because of the higher
operating temperature of portion 550 due to the higher Curie temperature in
this portion.
In some embodiments, a relatively thin conductive layer is used to provide the
majority of the electrically
resistive heat output of the temperature limited heater at temperatures up to
a temperature at or near the Curie
temperature of the ferromagnetic conductor. Such a temperature limited heater
may be used as the heating member
in an insulated conductor heater. The heating member of the insulated
conductor heater may be located inside a
sheath with an insulation layer between the sheath and the heating member.
FIGS. 51A and 51B depict cross-sectional representations of an embodiment of
the insulated conductor
heater with the temperature limited heater as the heating member. Insulated
conductor 558 includes core 508,
ferromagnetic conductor 512, inner conductor 490, electrical insulator 500,
and jacket 506. Core 508 is a copper
core. Ferromagnetic conductor 512 is, for example, iron or an iron alloy.
Inner conductor 490 is a relatively thin conductive layer of non-ferromagnetic
material with a higher
electrical conductivity than ferromagnetic conductor 512. In certain
embodiments, inner conductor 490 is copper.
Inner conductor 490 may be a copper alloy. Copper alloys typically have a
flatter resistance versus temperature
profile than pure copper. A flatter resistance versus temperature profile may
provide less variation in the heat output
as a function of temperature up to the Curie temperature. In some embodiments,
inner conductor 490 is copper with
= 6% by weight nickel (for example, CuNi6 or LOHMTm). In some embodiments,
inner conductor 490 is
CuNil0FelMn alloy. Below the Curie temperature of ferromagnetic conductor 512,
the magnetic properties of the
ferromagnetic conductor confine the majority of the flow of electrical current
to inner conductor 490. Thus, inner
conductor 490 provides the majority of the resistive heat output of insulated
conductor 558 below the Curie
temperature.
In certain embodiments, inner conductor 490 is dimensioned, along with core
508 and ferromagnetic
conductor 512, so that the inner conductor provides a desired amount of heat
output and a desired turndown ratio.
For example, inner conductor 490 may have a cross-sectional area that is
around 2 or 3 times less than the cross-
sectional area of core 508. Typically, inner conductor 490 has to have a
relatively small cross-sectional area to
provide a desired heat output if the inner conductor is copper or copper
alloy. In an embodiment with copper inner
conductor 490, core 508 has a diameter of 0.66 cm, ferromagnetic conductor 512
has an outside diameter of 0.91 cm,
inner conductor 490 has an outside diameter of 1.03 cm, electrical insulator
500 has an outside diameter of 1.53 cm,
and jacket 506 has an outside diameter of 1.79 cm. In an embodiment with a
CuNi6 inner conductor 490, core 508
has a diameter of 0.66 cm, ferromagnetic conductor 512 has an outside diameter
of 0.91 cm, inner conductor 490 has
an outside diameter of 1.12 cm, electrical insulator 500 has an outside
diameter of 1.63 cm, and jacket 506 has an
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outside diameter of 1.88 cm. Such insulated conductors are typically smaller
and cheaper to manufacture than
insulated conductors that do not use the thin inner conductor to provide the
majority of heat output below the Curie
temperature.
Electrical insulator 500 may be magnesium oxide, aluminum oxide, silicon
dioxide, beryllium oxide, boron
nitride, silicon nitride, or combinations thereof. In certain embodiments,
electrical insulator 500 is a compacted
powder of magnesium oxide. In some embodiments, electrical insulator 500
includes beads of silicon nitride.
In certain embodiments, a small layer of material is placed between electrical
insulator 500 and inner
conductor 490 to inhibit copper from migrating into the electrical insulator
at higher temperatures. For example, the
small layer of nickel (for example, about 0.5 mm of nickel) may be placed
between electrical insulator 500 and inner
conductor 490.
Jacket 506 is made of a corrosion resistant material such as, but not limited
to, 347 stainless steel, 347H
stainless steel, 446 stainless steel, or 825 stainless steel. In some
embodiments, jacket 506 provides some
mechanical strength for insulated conductor 558 at or above the Curie
temperature of ferromagnetic conductor 512.
In certain embodiments, jacket 506 is not used to conduct electrical current.
In certain embodiments of temperature limited heaters, three temperature
limited heaters are coupled
together in a three-phase wye configuration. Coupling three temperature
limited heaters together in the three-phase
wye configuration lowers the current in each of the individual temperature
limited heaters because the current is split
between the three individual heaters. Lowering the current in each individual
temperature limited heater allows each
heater to have a small diameter. The lower currents allow for higher relative
magnetic permeabilities in each of the
individual temperature limited heaters and, thus, higher turndown ratios. In
addition, there may be no return current
needed for each of the individual temperature limited heaters. Thus, the
turndown ratio remains higher for each of
the individual temperature limited heaters than if each temperature limited
heater had its own return current path.
In the three-phase wye configuration, individual temperature limited heaters
may be coupled together by
shorting the sheaths, jackets, or canisters of each of the individual
temperature limited heaters to the electrically
conductive sections (the conductors providing heat) at their terminating ends
(for example, the ends of the heaters at
the bottom of a heater wellbore). In some embodiments, the sheaths, jackets,
canisters, and/or electrically
conductive sections are coupled to a support member that supports the
temperature limited heaters in the wellbore.
FIG. 52A depicts an embodiment for installing and coupling heaters in a
wellbore. The embodiment in
FIG. 52A depicts insulated conductor heaters being installed into the
wellbore. Other types of heaters, such as
conductor-in-conduit heaters, may also be installed in the wellbore using the
embodiment depicted. Also, in FIG.
52A, two insulated conductors 558 are shown while a third insulated conductor
is not seen from the view depicted.
Typically, three insulated conductors 558 would be coupled to support member
560, as shown in FIG. 52B. In an
embodiment, support member 560 is a thick walled 347H pipe. In some
embodiments, thermocouples or other
temperature sensors are placed inside support member 560. The three insulated
conductors may be coupled in a
three-phase wye configuration.
In FIG. 52A, insulated conductors 558 are coiled on coiled tubing rigs 562. As
insulated conductors 558
are uncoiled from rigs 562, the insulated conductors are coupled to support
member 560. In certain embodiments,
insulated conductors 558 are simultaneously uncoiled and/or simultaneously
coupled to support member 560.
Insulated conductors 558 may be coupled to support member 560 using metal (for
example, 304 stainless steel or
Inconel alloys) straps 564. In some embodiments, insulated conductors 558 are
coupled to support member 560
using other types of fasteners such as buckles, wire holders, or snaps.
Support member 560 along with insulated
conductors 558 are installed into opening 522. In some embodiments, insulated
conductors 558 are coupled together
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without the use of a support member. For example, one or more straps 564 may
be used to couple insulated
conductors 558 together.
Insulated conductors 558 may be electrically coupled to each other at a lower
end of the insulated
conductors. In a three-phase wye configuration, insulated conductors 558
operate without a current return path. In
certain embodiments, insulated conductors 558 are electrically coupled to each
other in contactor section 566. In
section 566, sheaths, jackets, canisters, and/or electrically conductive
sections are electrically coupled to each other
and/or to support member 560 so that insulated conductors 558 are electrically
coupled in the section.
In certain embodiments, the sheaths of insulated conductors 558 are shorted to
the conductors of the
insulated conductors. FIG. 52C depicts an embodiment of insulated conductor
558 with the sheath shorted to the
conductors. Sheath 506 is electrically coupled to core 508, ferromagnetic
conductor 512, and inner conductor 490
using termination 568. Termination 568 may be a metal strip or a metal plate
at the lower end of insulated conductor
558. For example, termination 568 may be a copper plate coupled to sheath 506,
core 508, ferromagnetic conductor
512, and inner conductor 490 so that they are shorted together. In some
embodiments, termination 568 is welded or
brazed to sheath 506, core 508, ferromagnetic conductor 512, and inner
conductor 490.
The sheaths of individual insulated conductors 558 may be shorted together to
electrically couple the
conductors of the insulated conductors, depicted in FIGS. 52A and 52B. In some
embodiments, the sheaths may be
shorted together because the sheaths are in physical contact with each other.
For example, the sheaths may in
physical contact if the sheaths are strapped together by straps 564. In some
embodiments, the lower ends of the
sheaths are physically coupled (for example, welded) at the surface of opening
522 before insulated conductors 558
are installed into the opening.
In some embodiments, a long temperature limited heater (for example, a
temperature limited heater in
which the support member provides a majority of the heat output below the
Curie temperature of the ferromagnetic
conductor) is formed from several sections of heater. The sections of heater
may be coupled using a welding
process. FIG. 53 depicts an embodiment for coupling together sections of a
long temperature limited heater. Ends
of ferromagnetic conductors 512 and ends of electrical conductors 538 (support
members 514) are beveled to
facilitate coupling the sections of the heater. Core 508 has recesses to allow
core coupling material 570 to be placed
inside the abutted ends of the heater. Core coupling material 570 may be a pin
or dowel that fits tightly in the
recesses of cores 508. Core coupling material 570 may be made out of the same
material as cores 508 or a material
suitable for coupling the cores together. Core coupling material 570 allows
the heaters to be coupled together
without welding cores 508 together. Cores 508 are coupled together as a "pin"
or "box" joint.
Beveled ends of ferromagnetic conductors 512 and electrical conductors 538 may
be coupled together with
coupling material 572. In certain embodiments, ends of ferromagnetic
conductors 512 and electrical conductors 538
are welded (for example, orbital welded) together. Coupling material 572 may
be 625 stainless steel or any other
suitable non-ferromagnetic material for welding together ferromagnetic
conductors 512 and/or electrical conductors
538. Using beveled ends when coupling together sections of the heater may
produce a reliable and durable coupling
between the sections of the heater.
During heating with the temperature limited heater, core coupling material 570
may expand more radially
than ferromagnetic conductors 512, electrical conductors 538, and/or coupling
material 572. The greater expansion
of core coupling material 570 maintains good electrical contact with the core
coupling material. At the coupling
junction of the heater, electricity flows through core coupling material 570
rather than coupling material 572. This
flow of electricity inhibits heat generation at the coupling junction so that
the junction remains at lower temperatures
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than other portions of the heater during application of electrical current to
the heater. The corrosion resistance and
strength of the coupling junction is increased by maintaining the junction at
lower temperatures.
In certain embodiments, the junction may be enclosed in a shield during
orbital welding to ensure reliability
of the weld. If the junction is not enclosed, disturbance of the inert gas
caused by wind, humidity or other conditions
may cause oxidation and/or porosity of the weld. Without a shield, a first
portion of the weld was formed and
allowed to cool. A grinder would be used to remove the oxide layer. The
process would be repeated until the weld
was complete. Enclosing the junction in the shield with an inert gas allows
the weld to be formed with no oxidation,
thus allowing the weld to be formed in one pass with no need for grinding.
Enclosing the junction increases the
safety of forming the weld because the arc of the orbital welder is enclosed
in the shield during welding. Enclosing
the junction in the shield may reduce the time needed to form the weld.
Without a shield, producing each weld may
take 30 minutes or more. With the shield, each weld may take 10 minutes or
less.
FIG. 54 depicts an embodiment of a shield for orbital welding sections of a
long temperature limited heater.
Orbital welding may also be used to form canisters for freeze wells from
sections of pipe. Shield 574 may include
upper plate 576, lower plate 578, inserts 580, wall 582, hinged door 584,
first clamp member 586, and second clamp
member 588. Wall 582 may include one or more inert gas inlets. Wall 582, upper
plate 576, and/or lower plate 578
may include one or more openings for monitoring equipment or gas purging.
Shield 574 is configured to work with
an orbital welder, such as AMI Power Supply (Model 227) and AMI Orbital Weld
Head (Model 97-2375) available
from Arc Machines, Inc. (Pacoima, California, U.S.A.). Inserts 580 may be
withdrawn from upper plate 576 and
lower plate 578. The orbital weld head may be positioned in shield 574. Shield
574 may be placed around a lower
conductor of the conductors that are to be welded together. When shield is
positioned so that the end of the lower
conductor is at a desired position in the middle of the shield, first clamp
member may be fastened to second clamp
member to secure shield 574 to the lower conductor. The upper conductor may be
positioned in shield 574. Inserts
580 may be placed in upper plate 576 and lower plate 578.
Hinged door 584 may be closed. The orbital welder may be used to weld the
lower conductor to the upper
conductor. Progress of the welding operation may be monitored through viewing
windows 590. When the weld is
complete, shield 574 may be supported and first clamp member 586 may be
unfastened from second clamp member
588. One or both inserts 580 may be removed or partially removed from lower
plate 578 and upper plate 576 to
facilitate lowering of the conductor. The conductor may be lowered in the
wellbore until the end of the conductor is
located at a desired position in shield 574. Shield 574 may be secured to the
conductor with first clamp member 586
and second clamp member 588. Another conductor may be positioned in the
shield. Inserts 580 may be positioned
in upper and lower plates 576, 578; hinged door is closed 584; and the orbital
welder is used to weld the conductors
together. The process may be repeated until a desired length of conductor is
formed.
The shield may be used to weld joints of pipe over an opening in the
hydrocarbon containing formation.
Hydrocarbon vapors from the formation may create an explosive atmosphere in
the shield even though the inert gas
supplied to the shield inhibits the formation of dangerous concentrations of
hydrocarbons in the shield. A control
circuit may be coupled to a power supply for the orbital welder to stop power
to the orbital welder to shut off the arc
forming the weld if the hydrocarbon level in the shield rises above a selected
concentration. FIG. 55 depicts a
schematic representation of an embodiment of a shut off circuit for orbital
welding machine 600. An inert gas, such
as argon, may enter shield 574 through inlet 602. Gas may exit shield 574
through purge 604. Power supply 606
supplies electricity to orbital welding machine 600 through lines 608, 610.
Switch 612 may be located in line 608 to
orbital welding machine 600. Switch 612 may be electrically coupled to
hydrocarbon monitor 614. Hydrocarbon
monitor 614 may detect the hydrocarbon concentration in shield 574. If the
hydrocarbon concentration in shield
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becomes too high, for example, over 25% of a lower explosion limit
concentration, hydrocarbon monitor 614 may
open switch 612. When switch 612 is open, power to orbital welder 600 is
interrupted and the arc formed by the
orbital welder ends.
In some embodiments, the temperature limited heater is used to achieve lower
temperature heating (for
example, for heating fluids in a production well, heating a surface pipeline,
or reducing the viscosity of fluids in a
wellbore or near wellbore region). Varying the ferromagnetic materials of the
temperature limited heater allows for
lower temperature heating. In some embodiments, the ferromagnetic conductor is
made of material with a lower
Curie temperature than that of 446 stainless steel. For example, the
ferromagnetic conductor may be an alloy of iron
and nickel. The alloy may have between 30% by weight and 42% by weight nickel
with the rest being iron. In one
embodiment, the alloy is Invar 36. Invar 36 is 36% by weight nickel in iron
and has a Curie temperature of 277 C.
In some embodiments, an alloy is a three component alloy with, for example,
chromium, nickel, and iron. For
example, an alloy may have 6% by weight chromium, 42% by weight nickel, and
52% by weight iron. A 2.5 cm
diameter rod of Invar 36 has a turndown ratio of approximately 2 to 1 at the
Curie temperature. Placing the Invar 36
alloy over a copper core may allow for a smaller rod diameter. A copper core
may result in a high turndown ratio.
The insulator in lower temperature heater embodiments may be made of a high
performance polymer insulator (such
as PFA or PEEKTM) when used with alloys with a Curie temperature that is below
the melting point or softening
point of the polymer insulator.
In certain embodiments, a conductor-in-conduit temperature limited heater is
used in lower temperature
applications by using lower Curie temperature ferromagnetic materials. For
example, a lower Curie temperature
ferromagnetic material may be used for heating inside sucker pump rods.
Heating sucker pump rods may be useful
to lower the viscosity of fluids in the sucker pump or rod and/or to maintain
a lower viscosity of fluids in the sucker
pump rod. Lowering the viscosity of the oil may inhibit sticking of a pump
used to pump the fluids. Fluids in the
sucker pump rod may be heated up to temperatures less than about 250 C or
less than about 300 C. Temperatures
need to be maintained below these values to inhibit coking of hydrocarbon
fluids in the sucker pump system.
FIG. 56 depicts an embodiment of a temperature limited heater with a low
temperature ferromagnetic outer
conductor. Outer conductor 502 is glass sealing Alloy 42-6. Alloy 42-6 may be
obtained from Carpenter Metals
(Reading, Pennsylvania, U.S.A.) or Anomet Products, Inc. In some embodiments,
outer conductor 502 includes
other compositions and/or materials to get various Curie temperatures (for
example, Carpenter Temperature
Compensator "32" (Curie temperature of 199 C; available from Carpenter
Metals) or Invar 36). In an embodiment,
conductive layer 510 is coupled (for example, clad, welded, or brazed) to
outer conductor 502. Conductive layer 510
is a copper layer. Conductive layer 510 improves a turndown ratio of outer
conductor 502. Jacket 506 is a
ferromagnetic metal such as carbon steel. Jacket 506 protects outer conductor
502 from a corrosive environment.
Inner conductor 490 may have electrical insulator 500. Electrical insulator
500 may be a mica tape winding with
overlaid fiberglass braid. In an embodiment, inner conductor 490 and
electrical insulator 500 are a 4/0 MGT-1000
furnace cable or 3/0 MGT-1000 furnace cable. 4/0 MGT-1000 furnace cable or 3/0
MGT-1000 furnace cable is
available from Allied Wire and Cable (Phoenixville, Pennsylvania, U.S.A.). In
some embodiments, a protective
braid such as a stainless steel braid may be placed over electrical insulator
500.
Conductive section 504 electrically couples inner conductor 490 to outer
conductor 502 and/or jacket 506.
In some embodiments, jacket 506 touches or electrically contacts conductive
layer 510 (for example, if the heater is
placed in a horizontal configuration). If jacket 506 is a ferromagnetic metal
such as carbon steel (with a Curie
temperature above the Curie temperature of outer conductor 502), current will
propagate only on the inside of the
jacket. Thus, the outside of the jacket remains electrically uncharged during
operation. In some embodiments,
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jacket 506 is drawn down (for example, swaged down in a die) onto conductive
layer 510 so that a tight fit is made
between the jacket and the conductive layer. The heater may be spooled as
coiled tubing for insertion into a
wellbore. In other embodiments, an annular space is present between conductive
layer 510 and jacket 506, as
depicted in FIG. 56.
FIG. 57 depicts an embodiment of a temperature limited conductor-in-conduit
heater. Conduit 518 is a
hollow sucker rod made of a ferromagnetic metal such as Alloy 42-6, Alloy 32,
Alloy 52, Invar 36, iron-nickel-
chromium alloys, iron-nickel alloys, nickel alloys, or nickel-chromium alloys.
Inner conductor 490 has electrical
insulator 500. Electrical insulator 500 is a mica tape winding with overlaid
fiberglass braid. In an embodiment,
inner conductor 490 and electrical insulator 500 are a 4/0 MGT-1000 furnace
cable or 3/0 MGT-I000 furnace cable.
In some embodiments, polymer insulations are used for lower temperature Curie
heaters. In certain embodiments, a
protective braid is placed over electrical insulator 500. Conduit 518 has a
wall thickness that is greater than the skin
depth at the Curie temperature (for example, 2 to 3 times the skin depth at
the Curie temperature). In some
embodiments, a more conductive conductor is coupled to conduit 518 to increase
the turndown ratio of the heater.
FIG. 58 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater. Conductor 516 is coupled (for example, clad, coextruded, press
fit, drawn inside) to ferromagnetic
conductor 512. A metallurgical bond between conductor 516 and ferromagnetic
conductor 512 is favorable.
Ferromagnetic conductor 512 is coupled to the outside of conductor 516 so that
current propagates through the skin
depth of the ferromagnetic conductor at room temperature. Conductor 516
provides mechanical support for
ferromagnetic conductor 512 at elevated temperatures. Ferromagnetic conductor
512 is iron, an iron alloy (for
example, iron with 10% to 27% by weight chromium for corrosion resistance), or
any other ferromagnetic material.
In one embodiment, conductor 516 is 304 stainless steel and ferromagnetic
conductor 512 is 446 stainless steel.
Conductor 516 and ferromagnetic conductor 512 are electrically coupled to
conduit 518 with sliding connector 528.
Conduit 518 may be a non-ferromagnetic material such as austenitic stainless
steel.
FIG. 59 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater. Conduit 518 is coupled to ferromagnetic conductor 512 (for
example, clad, press fit, or drawn inside
of the ferromagnetic conductor). Ferromagnetic conductor 512 is coupled to the
inside of conduit 518 to allow
current to propagate through the skin depth of the ferromagnetic conductor at
room temperature. Conduit 518
provides mechanical support for ferromagnetic conductor 512 at elevated
temperatures. Conduit 518 and
ferromagnetic conductor 512 are electrically coupled to conductor 516 with
sliding connector 528.
FIG. 60 depicts a cross-sectional view of an embodiment of a conductor-in-
conduit temperature limited
heater. Conductor 516 may surround core 508. In an embodiment, conductor 516
is 347H stainless steel and core
508 is copper. Conductor 516 and core 508 may be formed together as a
composite conductor. Conduit 518 may
include ferromagnetic conductor 512. In an embodiment, ferromagnetic conductor
512 is Sumitomo HCM12A or
446 stainless steel. Ferromagnetic conductor 512 may have a Schedule XXH
thickness so that the conductor is
inhibited from deforming. In certain embodiments, conduit 518 also includes
jacket 506. Jacket 506 may include
corrosion resistant material that inhibits electrons from flowing away from
the heater and into a subsurface formation
at higher temperatures (for example, temperatures near the Curie temperature
of ferromagnetic conductor 512). For
example, jacket 506 may be about a 0.4 cm thick sheath of 410 stainless steel.
Inhibiting electrons from flowing to
the formation may increase the safety of using the heater in the subsurface
formation.
FIG. 61 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater with an insulated conductor. Insulated conductor 558 may
include core 508, electrical insulator 500,
and jacket 506. Jacket 506 may be made of a corrosion resistant material (for
example, stainless steel). Endcap 616
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CA 02871784 2014-11-18
may be placed at an end of insulated conductor 558 to couple core 508 to
sliding connector 528. Endcap 616 may be
made of non-corrosive, electrically conducting materials such as nickel or
stainless steel. Endcap 616 may be
coupled to the end of insulated conductor 558 by any suitable method (for
example, welding, soldering, braising).
Sliding connector 528 may electrically couple core 508 and endcap 616 to
ferromagnetic conductor 512. Conduit
518 may provide support for ferromagnetic conductor 512 at elevated
temperatures.
FIG. 62 depicts a cross-sectional representation of an embodiment of a
conductor-in-conduit temperature
limited heater with an insulated conductor. Insulated conductor 558 includes
core 508, electrical insulator 500, and
jacket 506. Jacket 506 is made of a highly electrically conductive material
such as copper. Core 508 is made of a
lower temperature ferromagnetic material such as such as Alloy 42-6, Alloy 32,
Invar 36, iron-nickel-chromium
alloys, iron-nickel alloys, nickel alloys, or nickel-chromium alloys. In
certain embodiments, the materials of jacket
506 and core 508 are reversed so that the jacket is the ferromagnetic
conductor and the core is the highly conductive
portion of the heater. Ferromagnetic material used in jacket 506 or core 508
may have a thickness greater than the
skin depth at the Curie temperature (for example, 2 to 3 times the skin depth
at the Curie temperature). Endcap 616
is placed at an end of insulated conductor 558 to couple core 508 to sliding
connector 528. Endcap 616 is made of
corrosion resistant, electrically conducting materials such as nickel or
stainless steel. In certain embodiments,
conduit 518 is a hollow sucker rod made from, for example, carbon steel.
In certain embodiments, a temperature limited heater includes a flexible cable
(for example, a furnace
cable) as the inner conductor. For example, the inner conductor may be a 27%
nickel-clad or stainless steel-clad
stranded copper wire with four layers of mica tape surrounded by a layer of
ceramic and/or mineral fiber (for
example, alumina fiber, aluminosilicate fiber, borosilicate fiber, or
aluminoborosilicate fiber). A stainless steel-clad
stranded copper wire furnace cable may be available from Anomet Products, Inc.
The inner conductor may be rated
for applications at temperatures of 1000 C or higher. The inner conductor may
be pulled inside a conduit. The
conduit may be a ferromagnetic conduit (for example, a 3/4" Schedule 80 446
stainless steel pipe). The conduit may
be covered with a layer of copper, or other electrical conductor, with a
thickness of about 0.3 cm or any other
suitable thickness. The assembly may be placed inside a support conduit (for
example, a 1-1/4" Schedule 80 347H or
347HH stainless steel tubular). The support conduit may provide additional
creep-rupture strength and protection for
the copper and the inner conductor. For uses at temperatures greater than
about 1000 C, the inner copper conductor
may be plated with a more corrosion resistant alloy (for example, Incoloy
825) to inhibit oxidation. In some
embodiments, the top of the temperature limited heater is sealed to inhibit
air from contacting the inner conductor.
The temperature limited heater may be a single-phase heater or a three-phase
heater. In a three-phase heater
embodiment, the temperature limited heater has a delta or a wye configuration.
Each of the three ferromagnetic
conductors in the three-phase heater may be inside a separate sheath. A
connection between conductors may be
made at the bottom of the heater inside a splice section. The three conductors
may remain insulated from the sheath
inside the splice section.
FIG. 63 depicts an embodiment of a three-phase temperature limited heater with
ferromagnetic inner
conductors. Each leg 618 has inner conductor 490, core 508, and jacket 506.
Inner conductors 490 are ferritic
stainless steel or 1% carbon steel. Inner conductors 490 have core 508. Core
508 may be copper. Each inner
conductor 490 is coupled to its own jacket 506. Jacket 506 is a sheath made of
a corrosion resistant material (such as
304H stainless steel). Electrical insulator 500 is placed between inner
conductor 490 and jacket 506. Inner
conductor 490 is ferritic stainless steel or carbon steel with an outside
diameter of 1.14 cm and a thickness of 0.445
cm. Core 508 is a copper core with a 0.25 cm diameter. Each leg 618 of the
heater is coupled to terminal block 620.
Terminal block 620 is filled with insulation material 622 and has an outer
surface of stainless steel. Insulation
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material 622 is, in some embodiments, silicon nitride, boron nitride,
magnesium oxide or other suitable electrically
insulating material. Inner conductors 490 of legs 618 are coupled (welded) in
terminal block 620. Jackets 506 of
legs 618 are coupled (welded) to an outer surface of terminal block 620.
Terminal block 620 may include two
halves coupled around the coupled portions of legs 618.
In some embodiments, the three-phase heater includes three legs that are
located in separate wellbores. The
legs may be coupled in a common contacting section (for example, a central
wellbore, a connecting wellbore, or a
solution filled contacting section). FIG. 64 depicts an embodiment of
temperature limited heaters coupled in a three-
phase configuration. Each leg 624, 626, 628 may be located in separate
openings 522 in hydrocarbon layer 460.
Each leg 624, 626, 628 may include heating element 630. Each leg 624, 626, 628
may be coupled to single
contacting element 632 in one opening 522. Contacting element 632 may
electrically couple legs 624, 626, 628
together in a three-phase configuration. Contacting element 632 may be located
in, for example, a central opening in
the formation. Contacting element 632 may be located in a portion of opening
522 below hydrocarbon layer 460 (for
example, in the underburden). In certain embodiments, magnetic tracking of a
magnetic element located in a central
opening (for example, opening 522 of leg 626) is used to guide the formation
of the outer openings (for example,
openings 522 of legs 624 and 628) so that the outer openings intersect the
central opening. The central opening may
be formed first using standard wellbore drilling methods. Contacting element
632 may include funnels, guides, or
catchers for allowing each leg to be inserted into the contacting element.
FIG. 65 depicts an embodiment of three heaters coupled in a three-phase
configuration. Conductor "legs"
624, 626, 628 are coupled to three-phase transformer 634. Transformer 634 may
be an isolated three-phase
transformer. In certain embodiments, transformer 634 provides three-phase
output in a wye configuration, as shown
in FIG. 65. Input to transformer 634 may be made in any input configuration
(such as the delta configuration shown
in FIG. 65). Legs 624, 626, 628 each include lead-in conductors 636 in the
overburden of the formation coupled to
heating elements 630 in hydrocarbon layer 460. Lead-in conductors 636 include
copper with an insulation layer.
For example, lead-in conductors 636 may be a 4-0 copper cables with TEFLON
insulation, a copper rod with
polyurethane insulation, or other metal conductors such as bare copper or
aluminum. In certain embodiments, lead-
in conductors 636 are located in an overburden portion of the formation. The
overburden portion may include
overburden casings 530. Heating elements 630 may be temperature limited heater
heating elements. In an
= embodiment, heating elements 630 are 410 stainless steel rods (for
example, 3.1 cm diameter 410 stainless steel
rods). In some embodiments, heating elements 630 are composite temperature
limited heater heating elements (for
example, 347 stainless steel, 410 stainless steel, copper composite heating
elements; 347 stainless steel, iron, copper
composite heating elements; or 410 stainless steel and copper composite
heating elements). In certain embodiments,
heating elements 630 have a length of at least about 10 m to about 2000 m,
about 20 m to about 400 m, or about 30
m to about 300 m.
In certain embodiments, heating elements 630 are exposed to hydrocarbon layer
460 and fluids from the
hydrocarbon layer. Thus, heating elements 630 are "bare metal" or "exposed
metal" heating elements. Heating
elements 630 may be made from a material that has an acceptable sulfidation
rate at high temperatures used for
pyrolyzing hydrocarbons. In certain embodiments, heating elements 630 are made
from material that has a
sulfidation rate that decreases with increasing temperature over at least a
certain temperature range (for example, 500
C to 650 C, 530 C to 650 C, or 550 C to 650 C). For example, 410
stainless steel may have a sulfidation rate
that decreases with increasing temperature between 530 C and 650 C. Using
such materials reduces corrosion
problems due to sulfur-containing gases (such as H2S) from the formation. In
certain embodiments, heating
elements 630 are made from material that has a sulfidation rate below a
selected value in a temperature range. In
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some embodiments, heating elements 630 are made from material that has a
sulfidation rate at most about 25 mils
per year at a temperature between about 800 C and about 880 C. In some
embodiments, the sulfidation rate is at
most about 35 mils per year at a temperature between about 800 C and about
880 C, at most about 45 mils per year
at a temperature between about 800 C and about 880 C, or at most about 55
mils per year at a temperature between
about 800 C and about 880 C. Heating elements 630 may also be substantially
inert to galvanic corrosion.
In some embodiments, heating elements 630 have a thin electrically insulating
layer such as aluminum
oxide or thermal spray coated aluminum oxide. In some embodiments, the thin
electrically insulating layer is a
ceramic composition such as an enamel coating. Enamel coatings include, but
are not limited to, high temperature
porcelain enamels. High temperature porcelain enamels may include silicon
dioxide, boron oxide, alumina, and
alkaline earth oxides (CaO or MgO), and minor amounts of alkali oxides (Na20,
K20, Li0). The enamel coating
may be applied as a finely ground slurry by dipping the heating element into
the slurry or spray coating the heating
element with the slurry. The coated heating element is then heated in a
furnace until the glass transition temperature
is reached so that the slurry spreads over the surface of the heating element
and makes the porcelain enamel coating.
The porcelain enamel coating contracts when cooled below the glass transition
temperature so that the coating is in
compression. Thus, when the coating is heated during operation of the heater,
the coating is able to expand with the
heater without cracking.
The thin electrically insulating layer has low thermal impedance allowing heat
transfer from the heating
element to the formation while inhibiting current leakage between heating
elements in adjacent openings and/or
current leakage into the formation. In certain embodiments, the thin
electrically insulating layer is stable at
temperatures above at least 350 C, above 500 C, or above 800 C. In certain
embodiments, the thin electrically
insulating layer has an emissivity of at least 0.7, at least 0.8, or at least
0.9. Using the thin electrically insulating
layer may allow for long heater lengths in the formation with low current
leakage.
Heating elements 630 may be coupled to contacting elements 632 at or near the
underburden of the
formation. Contacting elements 632 are copper or aluminum rods or other highly
conductive materials. In certain
embodiments, transition sections 638 are located between lead-in conductors
636 and heating elements 630, and/or
between heating elements 630 and contacting elements 632. Transition sections
638 may be made of a conductive
material that is corrosion resistant such as 347 stainless steel over a copper
core. In certain embodiments, transition
sections 638 are made of materials that electrically couple lead-in conductors
636 and heating elements 630 while
providing little or no heat output. Thus, transition sections 638 help to
inhibit overheating of conductors and
insulation used in lead-in conductors 636 by spacing the lead-in conductors
from heating elements 630. Transition
section 638 may have a length of between about 3 m and about 9 m (for example,
about 6 m).
Contacting elements 632 are coupled to contactor 640 in contacting section 642
to electrically couple legs
624, 626, 628 to each other. In some embodiments, contact solution 644 (for
example, conductive cement) is placed
in contacting section 642 to electrically couple contacting elements 632 in
the contacting section. In certain
embodiments, legs 624, 626, 628 are substantially parallel in hydrocarbon
layer 460 and leg 624 continues
substantially vertically into contacting section 642. The other two legs 626,
628 are directed (for example, by
directionally drilling the wellbores for the legs) to intercept leg 624 in
contacting section 642.
Each leg 624, 626, 628 may be one leg of a three-phase heater embodiment so
that the legs are substantially
electrically isolated from other heaters in the formation and are
substantially electrically isolated from the formation.
Legs 624, 626, 628 may be arranged in a triangular pattern so that the three
legs form a triangular shaped three-phase
heater. In an embodiment, legs 624, 626, 628 are arranged in a triangular
pattern with 12 m spacing between the
legs (each side of the triangle has a length of 12 m).
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In certain embodiments, the thin electrically insulating layer allows for
relatively long, substantially
horizontal heater leg lengths in the hydrocarbon layer with a substantially u-
shaped heater. FIG. 66 depicts a side-
view representation of an embodiment of a substantially u-shaped three-phase
heater. First ends of legs 624, 626,
628 are coupled to transformer 634 at first location 646. In an embodiment,
transformer 634 is a three-phase AC
transformer. Ends of legs 624, 626, 628 are electrically coupled together with
connector 648 at second location 650.
Connector 648 electrically couples the ends of legs 624, 626, 628 so that the
legs can be operated in a three-phase
configuration. In certain embodiments, legs 624, 626, 628 are coupled to
operate in a three-phase wye configuration.
In certain embodiments, legs 624, 626, 628 are substantially parallel in
hydrocarbon layer 460. In certain
embodiments, legs 624, 626, 628 are arranged in a triangular pattern in
hydrocarbon layer 460. In certain
embodiments, heating elements 630 include a thin electrically insulating
material (such as a porcelain enamel
coating) to inhibit current leakage from the heating elements. In certain
embodiments, legs 624, 626, 628 are
electrically coupled so that the legs are substantially electrically isolated
from other heaters in the formation and are
substantially electrically isolated from the formation.
In certain embodiments, overburden casings (for example, overburden casings
530, depicted in FIGS. 65
and 66) in overburden 458 include materials that inhibit ferromagnetic effects
in the casings. Inhibiting
ferromagnetic effects in casings 530 reduces heat losses to the overburden. In
some embodiments, casings 530 may
include non-metallic materials such as fiberglass, polyvinylchloride (PVC),
chlorinated polyvinylchloride (CPVC),
or high-density polyethylene (HDPE). HDPEs with working temperatures in a
range for use in overburden 458
include HDPEs available from Dow Chemical Co., Inc. (Midland, Michigan,
U.S.A.). A non-metallic casing may
also eliminate the need for an insulated overburden conductor. In some
embodiments, casings 530 include carbon
steel coupled on the inside diameter of a non-ferromagnetic metal (for
example, carbon steel clad with copper or
aluminum) to inhibit ferromagnetic effects or inductive effects in the carbon
steel. Other non-ferromagnetic metals
include, but are not limited to, manganese steels with at least 10% by weight
manganese, iron aluminum alloys with
at least 18% by weight aluminum, and austentitic stainless steels such as 304
stainless steel or 316 stainless steel.
In certain embodiments, one or more non-ferromagnetic materials used in
casings 530 are used in a
wellhead coupled to the casings and legs 624, 626, 628. Using non-
ferromagnetic materials in the wellhead inhibits
undesirable heating of components in the wellhead. In some embodiments, a
purge gas (for example, carbon
dioxide, nitrogen or argon) is introduced into the wellhead and/or inside of
casings 530 to inhibit reflux of heated
gases into the wellhead and/or the casings.
In certain embodiments, one or more of legs 624, 626, 628 are installed in the
formation using coiled
tubing. In certain embodiments, coiled tubing is installed in the formation,
the leg is installed inside the coiled
tubing, and the coiled tubing is pulled out of the formation to leave the leg
installed in the formation. The leg may
be placed concentrically inside the coiled tubing. In some embodiments, coiled
tubing with the leg inside the coiled
tubing is installed in the formation and the coiled tubing is removed from the
formation to leave the leg installed in
the formation. The coiled tubing may extend only to a junction of hydrocarbon
layer 460 and contacting section 642
or to a point at which the leg begins to bend in the contacting section.
FIG. 67 depicts a top view representation of an embodiment of a plurality of
triads of three-phase heaters in
the formation. Each triad 652 includes legs A, B, C (which may correspond to
legs 624, 626, 628 depicted in FIGS.
65 and 66) that are electrically coupled by linkage 654. Each triad 652 is
coupled to its own electrically isolated
three-phase transformer so that the triads are substantially electrically
isolated from each other. Electrically isolating
the triads inhibits net current flow between triads.
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The phases of each triad 652 may be arranged so that legs A, B, C correspond
between triads as shown in
FIG. 67. In FIG. 67, legs A, B, C are arranged such that a phase leg (for
example, leg A) in a given triad is about
two triad heights from a same phase leg (leg A) in an adjacent triad. The
triad height is the distance from a vertex of
the triad to a midpoint of the line intersecting the other two vertices of the
triad. In certain embodiments, the phases
of triads 652 are arranged to inhibit net current flow between individual
triads. There may be some leakage of
current within an individual triad but little net current flows between two
triads due to the substantial electrical
isolation of the triads and, in certain embodiments, the arrangement of the
triad phases.
In the early stages of heating, an exposed heating element (for example,
heating element 630 depicted in
FIGS. 65 and 66) may leak some current to water or other fluids that are
electrically conductive in the formation so
that the formation itself is heated. After water or other electrically
conductive fluids are removed from the wellbore
(for example, vaporized or produced), the heating elements become electrically
isolated from the formation. Later,
when water is removed from the formation, the formation becomes even more
electrically resistant and heating of
the formation occurs even more predominantly via thermally conductive and/or
radiative heating. Typically, the
formation (the hydrocarbon layer) has an initial electrical resistance that
averages at least 10 ohm-m. In some
embodiments, the formation has an initial electrical resistance of at least
100 ohm-m or of at least 300 ohm=m.
Using the temperature limited heaters as the heating elements limits the
effect of water saturation on heater
efficiency. With water in the formation and in heater wellbores, there is a
tendency for electrical current to flow
between heater elements at the top of the hydrocarbon layer where the voltage
is highest and cause uneven heating in
the hydrocarbon layer. This effect is inhibited with temperature limited
heaters because the temperature limited
heaters reduce localized overheating in the heating elements and in the
hydrocarbon layer.
In certain embodiments, production wells are placed at a location at which
there is relatively little or zero
voltage potential. This location minimizes stray potentials at the production
well. Placing production wells at such
locations improves the safety of the system and reduces or inhibits undesired
heating of the production wells caused
by electrical current flow in the production wells. FIG. 68 depicts a top view
representation of the embodiment
depicted in FIG. 67 with production wells 206. In certain embodiments,
production wells 206 are located at or near
center of triad 652. In certain embodiments, production wells 206 are placed
at a location between triads at which
there is relatively little or zero voltage potential (at a location at which
voltage potentials from vertices of three triads
average out to relatively little or zero voltage potential). For example,
production well 206 may be at a location
equidistant from legs A of one triad, leg B of a second triad, and leg C of a
third triad, as shown in FIG. 68.
FIG. 69 depicts a top view representation of an embodiment of a plurality of
triads of three-phase heaters in
a hexagonal pattern in the formation. FIG. 70 depicts a top view
representation of an embodiment of a hexagon from
FIG. 69. Hexagon 656 includes two triads of heaters. The first triad includes
legs Al, B I, Cl electrically coupled
together by linkages 654 in a three-phase configuration. The second triad
includes legs A2, B2, C2 electrically
coupled together by linkages 654 in a three-phase configuration. The triads
are arranged so that corresponding legs
of the triads (for example, Al and A2, B1 and B2, Cl and C2) are at opposite
vertices of hexagon 656. The triads
are electrically coupled and arranged so that there is relatively little or
zero voltage potential at or near the center of
hexagon 656.
Production well 206 may be placed at or near the center of hexagon 656.
Placing production well 206 at or
near the center of hexagon 656 places the production well at a location that
reduces or inhibits undesired heating due
to electromagnetic effects caused by electrical current flow in the legs of
the triads and increases the safety of the
system. Having two triads in hexagon 656 provides for redundant heating around
production well 206. Thus, if one
triad fails or has to be turned off, production well 206 still remains at a
center of one triad.
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As shown in FIG. 69, hexagons 656 may be arranged in a pattern in the
formation such that adjacent
hexagons are offset. Using electrically isolated transformers on adjacent
hexagons may inhibit electrical potentials
in the formation so that little or no net current leaks between hexagons.
Triads of heaters and/or heater legs may be arranged in any shape or desired
pattern. For example, as
described above, triads may include three heaters and/or heater legs arranged
in an equilateral triangular pattern. In
some embodiments, triads include three heaters and/or heater legs arranged in
other triangular shapes (for example,
an isosceles triangle or a right angle triangle). In some embodiments, heater
legs in the triad cross each other (for
example, criss-cross) in the formation. In certain embodiments, triads
includes three heaters and/or heater legs
arranged sequentially along a straight line.
FIG. 71 depicts an embodiment with triads coupled to a horizontal connector
well. Triad 652A includes
legs 624A, 626A, 628A. Triad 652B includes legs 624B, 626B, 628B. Legs 624A,
626A, 628A and legs 624B,
626B, 628B may be arranged along a straight line on the surface of the
formation. In some embodiments, legs 624A,
626A, 628A are arranged along a straight line and offset from legs 624B, 626B,
628B, which may be arranged along
a straight line. Legs 624A, 626A, 628A and legs 624B, 626B, 628B include
heating elements 630 located in
hydrocarbon layer 460. Lead-in conductors 636 couple heating elements 630 to
the surface of the formation.
Heating elements 630 are coupled to contacting elements 632 at or near the
underburden of the formation. In certain
embodiments, transition sections (for example, transition sections 638
depicted in FIG. 65) are located between lead-
in conductors 636 and heating elements 630, and/or between heating elements
630 and contacting elements 632.
Contacting elements 632 are coupled to contactor 640 in contacting section 642
to electrically couple legs
624A, 626A, 628A to each other to form triad 652A and electrically couple legs
624B, 626B, 628B to each other to
form triad 652B. In certain embodiments, contactor 640 is a ground conductor
so that triad 652A and/or triad 652B
may be coupled in three-phase wye configurations. In certain embodiments,
triad 652A and triad 652B are
electrically isolated from each other. In some embodiments, triad 652A and
triad 652B are electrically coupled to
each other (for example, electrically coupled in series or parallel).
In certain embodiments, contactor 640 is a substantially horizontal contactor
located in contacting section
642. Contactor 640 may be a casing or a solid rod placed in a wellbore drilled
substantially horizontally in
contacting section 642. Legs 624A, 626A, 628A and legs 624B, 626B, 628B may be
electrically coupled to
contactor 640 by any method described herein or any method known in the art.
For example, containers with
thermite powder are coupled to contactor 640 (for example, by welding or
brazing the containers to the contactor);
legs 624A, 626A, 628A and legs 624B, 626B, 628B are placed inside the
containers; and the thermite powder is
activated to electrically couple the legs to the contactor. The containers may
be coupled to contactor 640 by, for
example, placing the containers in holes or recesses in contactor 640 or
coupled to the outside of the contactor and
then brazing or welding the containers to the contactor,
As shown in FIG. 65, contacting elements 632 of legs 624, 626, 628 may be
coupled using contactor 640
and/or contact solution 644. In certain embodiments, contacting elements 632
of legs 624, 626, 628 are physically
coupled, for example, through soldering, welding, or other techniques. FIGS.
72 and 73 depict embodiments for
coupling contacting elements 632 of legs 624, 626, 628. Legs 626, 628 may
enter the wellbore of leg 624 from any
direction desired. In one embodiment, legs 626, 628 enter the wellbore of leg
624 from approximately the same side
of the wellbore, as shown in FIG. 72. In an alternative embodiment, legs 626,
628 enter the wellbore of leg 624
from approximately opposite sides of the wellbore, as shown in FIG. 73.
Container 658 is coupled to contacting element 632 of leg 624. Container 658
may be soldered, welded, or
otherwise electrically coupled to contacting element 632. Container 658 is a
metal can or other container with at
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least one opening for receiving one or more contacting elements 632. In an
embodiment, container 658 is a can that
has an opening for receiving contacting elements 632 from legs 626, 628, as
shown in FIG. 72. In certain
embodiments, wellbores for legs 626, 628 are drilled parallel to the wellbore
for leg 624 through the hydrocarbon
layer that is to be heated and directionally drilled below the hydrocarbon
layer to intercept wellbore for leg 624 at an
angle between about 100 and about 20 from vertical. Wellbores may be
directionally drilled using known
techniques such as techniques used by Vector Magnetics, Inc.
In some embodiments, contacting elements 632 contact the bottom of container
658. Contacting elements
632 may contact the bottom of container 658 and/or each other to promote
electrical connection between the
contacting elements and/or the container. In certain embodiments, end portions
of contacting elements 632 are
annealed to a "dead soft" condition to facilitate entry into container 658. In
some embodiments, rubber or other
softening material is attached to end portions of contacting elements 632 to
facilitate entry into container 658. In
some embodiments, contacting elements 632 include reticulated sections, such
as knuckle-joints or limited rotation
knuckle-joints, to facilitate entry into container 658.
In certain embodiments, an electrical coupling material is placed in container
658. The electrical coupling
material may line the walls of container 658 or fill up a portion of the
container. In certain embodiments, the
electrical coupling material lines an upper portion, such as the funnel-shaped
portion shown in FIG. 74, of container
658. The electrical coupling material includes one or more materials that when
activated (for example, heated,
ignited, exploded, combined, mixed, and/or reacted) form a material that
electrically couples one or more elements
to each other. In an embodiment, the coupling material electrically couples
contacting elements 632 in container
658. In some embodiments, the coupling material metallically bonds to
contacting elements 632 so that the
contacting elements are metallically bonded to each other. In some
embodiments, container 658 is initially filled
with a high viscosity water-based polymer fluid to inhibit drill cuttings or
other materials from entering the container
prior to using the coupling material to couple the contacting elements. The
polymer fluid may be, but is not limited
to, a cross-linked XC polymer (available from Baroid Industrial Drilling
Products (Houston, Texas, U.S.A.), a frac
gel, or a cross-linked polyacrylamide gel.
In certain embodiments, the electrical coupling material is a low-temperature
solder that melts at relatively
low temperature and when cooled forms an electrical connection to exposed
metal surfaces. In certain embodiments,
the electrical coupling material is a solder that melts at a temperature below
the boiling point of water at the depth of
container 658. In one embodiment, the electrical coupling material is a 58% by
weight bismuth and 42% by weight
tin eutectic alloy. Other examples of such solders include, but are not
limited to, a 54% by weight bismuth, 16% by
weight tin, 30% by weight indium alloy, and a 48% by weight tin, 52% by weight
indium alloy. Such low-
temperature solders will displace water upon melting so that the water moves
to the top of container 658. Water at
the top of container 658 may inhibit heat transfer into the container and
thermally insulate the low-temperature
solder so that the solder remains at cooler temperatures and does not melt
during heating of the formation using the
heating elements.
Container 658 may be heated to activate the electrical coupling material to
facilitate the connection of
contacting elements 632. In certain embodiments, container 658 is heated to
melt the electrical coupling material in
the container. The electrical coupling material flows when melted and
surrounds contacting elements 632 in
container 658. Any water within container 658 will float to the surface of the
metal when the metal is melted. The
electrical coupling material is allowed to cool and electrically connects
contacting elements 632 to each other. In
certain embodiments, contacting elements 632 of legs 626, 628, the inside
walls of container 658, and/or the bottom
of the container are initially pre-tinned with electrical coupling material.
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End portions of contacting elements 632 of legs 624, 626, 628 may have shapes
and/or features that
enhance the electrical connection between the contacting elements and the
coupling material. The shapes and/or
features of contacting elements 632 may also enhance the physical strength of
the connection between the contacting
elements and the coupling material (for example, the shape and/or features of
the contacting element may anchor the
contacting element in the coupling material). Shapes and/or features for end
portions of contacting elements 632
include, but are not limited to, grooves, notches, holes, threads, serrated
edges, openings, and hollow end portions.
In certain embodiments, the shapes and/or features of the end portions of
contacting elements 632 are initially pre-
tinned with electrical coupling material.
FIG. 74 depicts an embodiment of container 658 with an initiator for melting
the coupling material. The
initiator is an electrical resistance heating element or any other element for
providing heat that activates or melts the
coupling material in container 658. In certain embodiments, heating element
660 is a heating element located in the
walls of container 658. In some embodiments, heating element 660 is located on
the outside of container 658.
Heating element 660 may be, for example, a nichrome wire, a mineral-insulated
conductor, a polymer-insulated
conductor, a cable, or a tape that is inside the walls of container 658 or on
the outside of the container. In some
embodiments, heating element 660 wraps around the inside walls of the
container or around the outside of the
container. Lead-in wire 662 may be coupled to a power source at the surface of
the formation. Lead-out wire 664
may be coupled to the power source at the surface of the formation. Lead-in
wire 662 and/or lead-out wire 664 may
be coupled along the length of leg 624 for mechanical support. Lead-in wire
662 and/or lead-out wire 664 may be
removed from the wellbore after melting the coupling material. Lead-in wire
662 and/or lead-out wire 664 may be
reused in other wellbores.
In some embodiments, container 658 has a funnel-shape, as shown in FIG. 74,
that facilitates the entry of
contacting elements 632 into the container. In certain embodiments, container
658 is made of or includes copper for
good electrical and thermal conductivity. A copper container 658 makes good
electrical contact with contacting
elements (such as contacting elements 632 shown in FIGS. 72 and 73) if the
contacting elements touch the walls
and/or bottom of the container.
FIG. 75 depicts an embodiment of container 658 with bulbs on contacting
elements 632. Protrusions 666
may be coupled to a lower portion of contacting elements 632. Protrusions 668
may be coupled to the inner wall of
container 658. Protrusions 666, 668 may be made of copper or another suitable
electrically conductive material.
Lower portion of contacting element 632 of leg 628 may have a bulbous shape,
as shown in FIG. 75. In certain
embodiments, contacting element 632 of leg 628 is inserted into container 658.
Contacting element 632 of leg 626 is
inserted after insertion of contacting element 632 of leg 628. Both legs may
then be pulled upwards simultaneously.
Protrusions 666 may lock contacting elements 632 into place against
protrusions 668 in container 658. A friction fit
is created between contacting elements 632 and protrusions 666, 668.
Lower portions of contacting elements 632 inside container 658 may include 410
stainless steel or any other
heat generating electrical conductor. Portions of contacting elements 632
above the heat generating portions of the
contacting elements include copper or another highly electrically conductive
material. Centralizers 524 may be
located on the portions of contacting elements 632 above the heat generating
portions of the contacting elements.
Centralizers 524 inhibit physical and electrical contact of portions of
contacting elements 632 above the heat
generating portions of the contacting elements against walls of container 658.
When contacting elements 632 are locked into place inside container 658 by
protrusions 666, 668, at least
some electrical current may be pass between the contacting elements through
the protrusions. As electrical current is
passed through the heat generating portions of contacting elements 632, heat
is generated in container 658. The
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CA 02871784 2014-11-18
generated heat may melt coupling material 670 located inside container 658.
Water in container 658 may boil. The
boiling water may convect heat to upper portions of container 658 and aid in
melting of coupling material 670.
Walls of container 658 may be thermally insulated to reduce heat losses out of
the container and allow the inside of
the container to heat up faster. Coupling material 670 flows down into the
lower portion of container 658 as the
coupling material melts. Coupling material 670 fills the lower portion of
container 658 until the heat generating
portions of contacting elements 632 are below the fill line of the coupling
material. Coupling material 670 then
electrically couples the portions of contacting elements 632 above the heat
generating portions of the contacting
elements. The resistance of contacting elements 632 decreases at this point
and heat is no longer generated in the
contacting elements and the coupling materials is allowed to cool.
In certain embodiments, container 658 includes insulation layer 672 inside the
housing of the container.
Insulation layer 672 may include thermally insulating materials to inhibit
heat losses from the canister. For example,
insulation layer 672 may include magnesium oxide, silicon nitride, or other
thermally insulating materials that
withstand operating temperatures in container 658. In certain embodiments,
container 658 includes liner 674 on an
inside surface of the container. Liner 674 may increase electrical
conductivity inside container 658. Liner 674 may
include electrically conductive materials such as copper or aluminum.
FIG. 76 depicts an alternative embodiment for container 658. Coupling material
in container 658 includes
powder 676. Powder 676 is a chemical mixture that produces a molten metal
product from a reaction of the
chemical mixture. In an embodiment, powder 676 is thermite powder. Powder 676
lines the walls of container 658
and/or is placed in the container. Igniter 678 is placed in powder 676.
Igniter 678 may be, for example, a
magnesium ribbon that when activated ignites the reaction of powder 676. When
powder 676 reacts, a molten metal
produced by the reaction flows and surrounds contacting elements 632 placed in
container 658. When the molten
metal cools, the cooled metal electrically connects contacting elements 632.
In some embodiments, powder 676 is
used in combination with another coupling material, such as a low-temperature
solder, to couple contacting elements
632. The heat of reaction of powder 676 may be used to melt the low
temperature-solder.
In certain embodiments, an explosive element is placed in container 658,
depicted in FIG. 72 or FIG. 76.
The explosive element may be, for example, a shaped charge explosive or other
controlled explosive element. The
explosive element may be exploded to crimp contacting elements 632 and/or
container 658 together so that the
contacting elements and the container are electrically connected. In some
embodiments, an explosive element is
used in combination with an electrical coupling material such as low-
temperature solder or thermite powder to
electrically connect contacting elements 632.
FIG. 77 depicts an alternative embodiment for coupling contacting elements 632
of legs 624, 626, 628.
Container 658A is coupled to contacting element 632 of leg 626. Container 658B
is coupled to contacting element
632 of leg 628. Container 658B is sized and shaped to be placed inside
container 658A. Container 658C is coupled
to contacting element 632 of leg 624. Container 658C is sized and shaped to be
placed inside container 658B. In
some embodiments, contacting element 632 of leg 624 is placed in container
658B without a container attached to
the contacting element. One or more of containers 658A, 658B, 658C may be
filled with a coupling material that is
activated to facilitate an electrical connection between contacting elements
632 as described above.
FIG. 78 depicts a side view representation of an embodiment for coupling
contacting elements using
temperature limited heating elements. Contacting elements 632 of legs 624,
626, 628 may have insulation 680 on
portions of the contacting elements above container 658. Container 658 may be
shaped and/or have guides at the top
to guide the insertion of contacting elements 632 into the container. Coupling
material 670 may be located inside
container 658 at or near a top of the container. Coupling material 670 may be,
for example, a solder material. In
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some embodiments, inside walls of container 658 are pre-coated with coupling
material or another electrically
conductive material such as copper or aluminum. Centralizers 524 may be
coupled to contacting elements 632 to
maintain a spacing of the contacting elements in container 658. Container 658
may be tapered at the bottom to push
lower portions of contacting elements 632 together for at least some
electrical contact between the lower portions of
the contacting elements.
Heating elements 682 may be coupled to portions of contacting elements 632
inside container 658. Heating
elements 682 may include ferromagnetic materials such as iron or stainless
steel. In an embodiment, heating
elements 682 are iron cylinders clad onto contacting elements 632. Heating
elements 682 may be designed with
dimensions and materials that will produce a desired amount of heat in
container 658. In certain embodiments, walls
of container 658 are thermally insulated with insulation layer 672, as shown
in FIG. 78 to inhibit heat loss from the
container. Heating elements 682 may be spaced so that contacting elements 632
have one or more portions of
exposed material inside container 658. The exposed portions include exposed
copper or another suitable highly
electrically conductive material. The exposed portions allow for better
electrical contact between contacting
elements 632 and coupling material 670 after the coupling material has been
melted, fills container 658, and is
allowed to cool.
In certain embodiments, heating elements 682 operate as temperature limited
heaters when a time-varying
current is applied to the heating elements. For example, a 400 Hz, AC current
may be applied to heating elements
682. Application of the time-varying current to contacting elements 632 causes
heating elements 682 to generate
heat and melt coupling material 670. Heating elements 682 may operate as
temperature limited heating elements
with a self-limiting temperature selected so that coupling material 670 is not
overheated. As coupling material 670
fills container 658, the coupling material makes electrical contact between
portions of exposed material on
contacting elements 632 and electrical current begins to flow through the
exposed material portions rather than
heating elements 682. Thus, the electrical resistance between the contacting
elements decreases. As this occurs,
temperatures inside container 658 begin to decrease and coupling material 670
is allowed to cool to create an
electrical contacting section between contacting elements 632. In certain
embodiments, electrical power to
contacting elements 632 and heating elements 682 is turned off when the
electrical resistance in the system falls
below a selected resistance. The selected resistance may indicate that the
coupling material has sufficiently
electrically connected the contacting elements. In some embodiments,
electrical power is supplied to contacting
elements 632 and heating elements 682 for a selected amount of time that is
determined to provide enough heat to
melt the mass of coupling material 670 provided in container 658.
FIG. 79 depicts a side view representation of an alternative embodiment for
coupling contacting elements
using temperature limited heating elements. Contacting element 632 of leg 624
may be coupled to container 658 by
welding, brazing, or another suitable method. Lower portion of contacting
element 632 of leg 628 may have a
bulbous shape. Contacting element 632 of leg 628 is inserted into container
658. Contacting element 632 of leg 626
is inserted after insertion of contacting element 632 of leg 628. Both legs
may then be pulled upwards
simultaneously, Protrusions 668 may lock contacting elements 632 into place
and a friction fit may be created
between the contacting elements 632. Centralizers 524 may inhibit electrical
contact between upper portions of
contacting elements 632.
Time-varying electrical current may be applied to contacting elements 632 so
that heating elements 682
generate heat. The generated heat may melt coupling material 670 located in
container 658 and be allowed to cool,
as described for the embodiment depicted in FIG. 78. After cooling of coupling
material 670, contacting elements
632 of legs 626, 628, shown in FIG. 79, are electrically coupled in container
658 with the coupling material. In
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some embodiments, lower portions of contacting elements 632 have protrusions
or openings that anchor the
contacting elements in cooled coupling material. Exposed portions of the
contacting elements provide a low
electrical resistance path between the contacting elements and the coupling
material.
FIG. 80 depicts a side view representation of another embodiment for coupling
contacting elements using
temperature limited heating elements. Contacting element 632 of leg 624 may be
coupled to container 658 by
welding, brazing, or another suitable method. Lower portion of contacting
element 632 of leg 628 may have a
bulbous shape. Contacting element 632 of leg 628 is inserted into container
658. Contacting element 632 of leg 626
is inserted after insertion of contacting element 632 of leg 628. Both legs
may then be pulled upwards
simultaneously. Protrusions 668 may lock contacting elements 632 into place
and a friction fit may be created
between the contacting elements 632. Centralizers 524 may inhibit electrical
contact between upper portions of
contacting elements 632.
End portions 632B of contacting elements 632 may be made of a ferromagnetic
material such as 410
stainless steel. Portions 632A may include non-ferromagnetic electrically
conductive material such as copper or
aluminum. Time-varying electrical current may be applied to contacting
elements 632 so that end portions 632B
generate heat due to the resistance of the end portions. The generated heat
may melt coupling material 670 located
in container 658 and be allowed to cool, as described for the embodiment
depicted in FIG. 78. After cooling of
coupling material 670, contacting elements 632 of legs 626, 628, shown in FIG.
79, are electrically coupled in
container 658 with the coupling material. Portions 632A may be below the fill
line of coupling material 670 so that
these portions of the contacting elements provide a low electrical resistance
path between the contacting elements
and the coupling material.
FIG. 81 depicts a side view representation of an alternative embodiment for
coupling contacting elements of
three legs of a heater. FIG. 82 depicts a top view representation of the
alternative embodiment for coupling
contacting elements of three legs of a heater depicted in FIG. 81. Container
658 may include inner container 684
and outer container 686. Inner container 684 may be made of copper or another
malleable, electrically conductive
metal such as aluminum. Outer container 686 may be made of a rigid material
such as stainless steel. Outer
container 686 protects inner container 684 and its contents from environmental
conditions outside of container 658.
Inner container 684 may be substantially solid with two openings 688 and 690.
Inner container 684 is
coupled to contacting element 632 of leg 624. For example, inner container 684
may be welded or brazed to
contacting element 632 of leg 624. Openings 688, 690 are shaped to allow
contacting elements 632 of legs 626, 628
to enter the openings as shown in FIG. 81. Funnels or other guiding mechanisms
may be coupled to the entrances to
openings 688, 690 to guide contacting elements 632 of legs 626, 628 into the
openings. Contacting elements 632 of
legs 624, 626, 628 may be made of the same material as inner container 684.
Explosive elements 700 may be coupled to the outer wall of inner container
684. In certain embodiments,
explosive elements 700 are elongated explosive strips that extend along the
outer wall of inner container 684.
Explosive elements 700 may be arranged along the outer wall of inner container
684 so that the explosive elements
are aligned at or near the centers of contacting elements 632, as shown in
FIG. 82. Explosive elements 700 are
arranged in this configuration so that energy from the explosion of the
explosive elements causes contacting
elements 632 to be pushed towards the center of inner container 684.
Explosive elements 700 may be coupled to battery 702 and timer 704. Battery
702 may provide power to
explosive elements 700 to initiate the explosion. Timer 704 may be used to
control the time for igniting explosive
elements 700. Battery 702 and timer 704 may be coupled to triggers 706.
Triggers 706 may be located in openings
688, 690. Contacting elements 632 may set off triggers 706 as the contacting
elements are placed into openings 688,
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690. When both triggers 706 in openings 688, 690 are triggered, timer 704 may
initiate a countdown before igniting
explosive elements 700. Thus, explosive elements 700 are controlled to explode
only after contacting elements 632
are placed sufficiently into openings 688, 690 so that electrical contact may
be made between the contacting
elements and inner container 684 after the explosions. Explosion of explosive
elements 700 crimps contacting
elements 632 and inner container 684 together to make electrical contact
between the contacting elements and the
inner container. In certain embodiments, explosive elements 700 fire from the
bottom towards the top of inner
container 684. Explosive elements 700 may be designed with a length and
explosive power (band width) that gives
an optimum electrical contact between contacting elements 632 and inner
container 684.
In some embodiments, triggers 706, battery 702, and timer 704 may be used to
ignite a powder (for
example, copper thermite powder) inside a container (for example, container
658 or inner container 684). Battery
702 may charge a magnesium ribbon or other ignition device in the powder to
initiate reaction of the powder to
produce a molten metal product. The molten metal product may flow and then
cool to electrically contact the
contacting elements.
In certain embodiments, electrical connection is made between contacting
elements 632 through mechanical
means. FIG. 83 depicts an embodiment of contacting element 632 with a brush
contactor. Brush contactor 708 is
coupled to a lower portion of contacting element 632. Brush contactor 708 may
be made of a malleable, electrically
=
conductive material such as copper or aluminum. Brush contactor 708 may be a
webbing of material that is
compressible and/or flexible. Centralizer 524 may be located at or near the
bottom of contacting element 632.
FIG. 84 depicts an embodiment for coupling contacting elements 632 with brush
contactors 708. Brush
contactors 708 are coupled to each contacting element 632 of legs 624, 626,
628. Brush contactors 708 compress
against each other and interlace to electrically couple contacting elements
632 of legs 624, 626, 628. Centralizers
524 maintain spacing between contacting elements 632 of legs 624, 626, 628 so
that interference and/or clearance
issues between the contacting elements are inhibited.
In certain embodiments, contacting elements 632 (depicted in FIGS. 72-84) are
coupled in a zone of the
formation that is cooler than the layer of the formation to be heated (for
example, in the underburden of the
formation). Contacting elements 632 are coupled in a cooler zone to inhibit
melting of the coupling material and/or
degradation of the electrical connection between the elements during heating
of the hydrocarbon layer above the
cooler zone. In certain embodiments, contacting elements 632 are coupled in a
zone that is at least about 3 m, at
least about 6 m, or at least about 9 m below the layer of the formation to be
heated. In some embodiments, the zone
has a standing water level that is above a depth of containers 658.
In certain embodiments, two legs in separate wellbores intercept in a single
contacting section. FIG. 85
depicts an embodiment of two temperature limited heaters coupled in a single
contacting section. Legs 624 and 626
include one or more heating elements 630. Heating elements 630 may include one
or more electrical conductors. In
certain embodiments, legs 624 and 626 are electrically coupled in a single-
phase configuration with one leg
positively biased versus the other leg so that current flows downhole through
one leg and returns through the other
leg.
Heating elements 630 in legs 624 and 626 may be temperature limited heaters.
In certain embodiments,
heating elements 630 are solid rod heaters. For example, heating elements 630
may be rods made of a single
ferromagnetic conductor element or composite conductors that include
ferromagnetic material. During initial
heating when water is present in the formation being heated, heating elements
630 may leak current into
hydrocarbon layer 460. The current leaked into hydrocarbon layer 460 may
resistively heat the hydrocarbon layer.
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In some embodiments (for example, in oil shale formations), heating elements
630 do not need support
members. Heating elements 630 may be partially or slightly bent, curved, made
into an S-shape, or made into a
helical shape to allow for expansion and/or contraction of the heating
elements. In certain embodiments, solid rod
heating elements 630 are placed in small diameter wellbores (for example,
about 3 3/4" (about 9.5 cm) diameter
wellbores). Small diameter wellbores may be less expensive to drill or form
than larger diameter wellbores, and
there will be less cuttings to dispose of.
In certain embodiments, portions of legs 624 and 626 in overburden 458 have
insulation (for example,
polymer insulation) to inhibit heating the overburden. Heating elements 630
may be substantially vertical and
substantially parallel to each other in hydrocarbon layer 460. At or near the
bottom of hydrocarbon layer 460, leg
624 may be directionally drilled towards leg 626 to intercept leg 626 in
contacting section 642. Drilling two
wellbores to intercept each other may be easier and less expensive than
drilling three or more wellbores to intercept
each other. The depth of contacting section 642 depends on the length of bend
in leg 624 needed to intercept leg
626. For example, for a 40 ft (about 12 m) spacing between vertical portions
of legs 624 and 626, about 200 ft
(about 61 m) is needed to allow the bend of leg 624 to intercept leg 626.
Coupling two legs may require a thinner
contacting section 642 than coupling three or more legs in the contacting
section.
FIG. 86 depicts an embodiment for coupling legs 624 and 626 in contacting
section 642. Heating elements
630 are coupled to contacting elements 632 at or near junction of contacting
section 642 and hydrocarbon layer 460.
Contacting elements 632 may be copper or another suitable electrical
conductor. In certain embodiments, contacting
element 632 in leg 626 is a liner with opening 710. Contacting element 632
from leg 624 passes through opening
710. Contactor 640 is coupled to the end of contacting element 632 from leg
624. Contactor 640 provides electrical
coupling between contacting elements in legs 624 and 626.
In certain embodiments, contacting elements 632 include one or more fins or
projections. The fins or
projections may increase an electrical contact area of contacting elements
632. In some embodiments, contacting
element 632 of leg 626 has an opening or other orifice that allows the
contacting element of 624 to couple to the
contacting element of leg 626.
In certain embodiments, legs 624 and 626 are coupled together to form a diad.
Three diads may be coupled
to a three-phase transformer to power the legs of the heaters. FIG. 87 depicts
an embodiment of three diads coupled
to a three-phase transformer. In certain embodiments, transformer 634 is a
delta three-phase transformer. Diad
712A includes legs 624A and 626A. Diad 712B includes legs 6248 and 626B. Diad
712C includes legs 624C and
626C. Diads 712A, 712B, 712C are coupled to the secondaries of transformer
634. Diad 712A is coupled to the
"A" secondary. Diad 712B is coupled to the "B" secondary. Diad 712C is coupled
to the "C" secondary.
Coupling the diads to the secondaries of the delta three-phase transformer
isolates the diads from ground.
Isolating the diads from ground inhibits leakage to the formation from the
diads. Coupling the diads to different
phases of the delta three-phase transformer also inhibits leakage between the
heating legs of the diads in the
formation.
In some embodiments, diads are used for treating formations using triangular
or hexagonal heater patterns.
FIG. 88 depicts an embodiment of groups of diads in a hexagonal pattern.
Heaters may be placed at the vertices of
each of the hexagons in the hexagonal pattern. Each group 714 of diads
(enclosed by dashed circles) may be
coupled to a separate three-phase transformer. "A", "B", and "C" inside groups
714 represent each diad (for
example, diads 712A, 712B, 712C depicted in FIG. 87) that is coupled to each
of the three secondary phases of the
transformer with each phase coupled to one diad (with the heaters at the
vertices of the hexagon). The numbers "1",
"2", and "3" inside the hexagons represent the three repeating types of
hexagons in the pattern depicted in FIG. 88.
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FIG. 89 depicts an embodiment of diads in a triangular pattern. Three diads
712A, 712B, 712C may be
enclosed in each group 714 of diads (enclosed by dashed rectangles). Each
group 714 may be coupled to a separate
three-phase transformer.
In certain embodiments, exposed metal heating elements are used in
substantially horizontal sections of u-
shaped wellbores. Substantially u-shaped wellbores may be used in tar sands
formations, oil shale formation, or
other formations with relatively thin hydrocarbon layers. Tar sands or thin
oil shale formations may have thin
shallow layers that are more easily and uniformly heated using heaters placed
in substantially u-shaped wellbores.
Substantially u-shaped wellbores may also be used to process formations with
thick hydrocarbon layers in
formations. In some embodiments, substantially u-shaped wellbores are used to
access rich layers in a thick
hydrocarbon formation.
Heaters in substantially u-shaped wellbores may have long lengths compared to
heaters in vertical
wellbores because horizontal heating sections do not have problems with creep
or hanging stress encountered with
vertical heating elements. Substantially u-shaped wellbores may make use of
natural seals in the formation and/or
the limited thickness of the hydrocarbon layer. For example, the wellbores may
be placed above or below natural
seals in the formation without punching large numbers of holes in the natural
seals, as would be needed with
vertically oriented wellbores. Using substantially u-shaped wellbores instead
of vertical wellbores may also reduce
the number of wells needed to treat a surface footprint of the formation.
Using less wells reduces capital costs for
equipment and reduces the environmental impact of treating the formation by
reducing the amount of wellbores on
the surface and the amount of equipment on the surface. Substantially u-shaped
wellbores may also utilize a lower
ratio of overburden section to heated section than vertical wellbores.
Substantially u-shaped wellbores may allow for flexible placement of opening
of the wellbores on the
surface. Openings to the wellbores may be placed according to the surface
topology of the formation. In certain
embodiments, the openings of wellbores are placed at geographically accessible
locations such as topological highs
(for examples, hills). For example, the wellbore may have a first opening on a
first topologic high and a second
opening on a second topologic high and the wellbore crosses beneath a
topologic low (for example, a valley with
alluvial fill) between the first and second topologic highs. This placement of
the openings may avoid placing
openings or equipment in topologic lows or other inaccessible locations. In
addition, the water level may not be
artesian in topologically high areas. Wellbores may be drilled so that the
openings are not located near
environmentally sensitive areas such as, but not limited to, streams, nesting
areas, or animal refuges.
FIG. 90 depicts a side-view representation of an embodiment of a heater with
an exposed metal heating
element placed in a substantially u-shaped wellbore. Heaters 716A, 716B, 716C
have first end portions at first
location 646 on surface 534 of the formation and second end portions at second
location 650 on the surface. Heaters
716A, 716B, 716C have sections 718 in overburden 458. Sections 718 are
configured to provide little or no heat
output. In certain embodiments, sections 718 include an insulated electrical
conductor such as insulated copper.
Sections 718 are coupled to heating elements 630.
In certain embodiments, portions of heating elements 630 are substantially
parallel in hydrocarbon layer
460. In certain embodiments, heating elements 630 are exposed metal heating
elements. In certain embodiments,
heating elements 630 are exposed metal temperature limited heating elements.
Heating elements 630 may include
ferromagnetic materials such as 9% by weight to 13% by weight chromium
stainless steel like 410 stainless steel,
chromium stainless steels such as T/P91 or T/P92, 409 stainless steel, VM12
(Vallourec and Mannesmann Tubes,
France) or iron-cobalt alloys for use as temperature limited heaters. In some
embodiments, heating elements 630 are
composite temperature limited heating elements such as 410 stainless steel and
copper composite heating elements
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or 347H, iron, copper composite heating elements. Heating elements 630 may
have lengths of at least about 100 m,
at least about 500 m, or at least about 1000 m, up to lengths of about 6000 m.
Heating elements 630 may be solid rods or tubulars. In certain embodiments,
solid rod heating elements
have diameters several times the skin depth at the Curie temperature of the
ferromagnetic material. Typically, the
solid rod heating elements may have diameters of 1.91 cm or larger (for
example, 2.5 cm, 3.2 cm, 3.81 cm, or 5.1
cm). In certain embodiments, tubular heating elements have wall thicknesses of
at least twice the skin depth at the
Curie temperature of the ferromagnetic material. Typically, the tubular
heating elements have outside diameters of
between about 2.5 cm and about 15.2 cm and wall thickness in range between
about 0.13 cm and about 1.01 cm.
In certain embodiments, tubular heating elements 630 allow fluids to be
convected through the tubular
heating elements. Fluid flowing through the tubular heating elements may be
used to preheat the tubular heating
elements, to initially heat the formation, and/or to recover heat from the
formation after heating is completed for the
in situ heat treatment process. Fluids that may be flow through the tubular
heating elements include, but are not
limited to, air, water, steam, helium, carbon dioxide or other fluids. In some
embodiments, a hot fluid, such as
carbon dioxide or helium, flows through the tubular heating elements to
provide heat to the formation. The hot fluid
may be used to provide heat to the formation before electrical heating is used
to provide heat to the formation. In
some embodiments, the hot fluid is used to provide heat in addition to
electrical heating. Using the hot fluid to
provide heat to the formation in addition to providing electrical heating may
be less expensive than using electrical
heating alone to provide heat to the formation. In some embodiments, water
and/or steam flows through the tubular
heating element to recover heat from the formation. The heated water and/or
steam may be used for solution mining
and/or other processes.
Transition sections 720 may couple heating elements 630 to sections 718. In
certain embodiments,
transition sections 720 include material that has a high electrical
conductivity but is corrosion resistant, such as 347
stainless steel over copper. In an embodiment, transition sections include a
composite of stainless steel clad over
copper. Transition sections 720 inhibit overheating of copper and/or
insulation in sections 718.
FIG. 91 depicts a representational top view of an embodiment of a surface
pattern of heaters depicted in
FIG. 90. Heaters 716A-L may be arranged in a repeating triangular pattern on
the surface of the formation, as shown
in FIG. 91. A triangle may be formed by heaters 716A, 716B, and 716C and a
triangle formed by heaters 716C,
716D, and 716E. In some embodiments, heaters 716A-L are arranged in a straight
line on the surface of the
formation. Heaters 716A-L have first end portions at first location 646 on the
surface and second end portions at
second location 650 on the surface. Heaters 716A-L are arranged such that (a)
the patterns at first location 646 and
second location 650 correspond to each other, (b) the spacing between heaters
is maintained at the two locations on
the surface, and/or (c) the heaters all have substantially the same length
(substantially the same horizontal distance
between the end portions of the heaters on the surface as shown in the top
view of FIG. 91).
As depicted in FIGS. 90 and 91, cables 722, 724 may be coupled to transformer
728 and one or more heater
units, such as the heater unit including heaters 716A, 716B, 716C. Cables 722,
724 may carry a large amount of
power. In certain embodiments, cables 722, 724 are capable of carrying high
currents with low losses. For example,
cables 722, 724 may be thick copper or aluminum conductors. The cables may
also have thick insulation layers. In
some embodiments, cable 722 and/or cable 724 may be superconducting cables.
The superconducting cables may be
cooled by liquid nitrogen. Superconducting cables are available from
Superpower, Inc. (Schenectady, New York,
U.S.A.). Superconducting cables may minimize power loss and reduce the size of
the cables needed to couple
transformer 728 to the heaters. In some embodiments, cables 722, 724 may be
made of carbon nanotubes. Carbon
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nanotubes as conductors may have about 1000 times the conductivity of copper
for the same diameter. Also, carbon
nanotubes may not require refrigeration during use.
In certain embodiments, bus bar 726A is coupled to first end portions of
heaters 716A-L and bus bar 726B
is coupled to second end portions of heaters 716A-L. Bus bars 726A,B
electrically couple heaters 716A-L to cables
722, 724 and transformer 728. Bus bars 726A,B distribute power to heaters 716A-
L. In certain embodiments, bus
bars 726A,B are capable of carrying high currents with low losses. In some
embodiments, bus bars 726A,B are
made of superconducting material such as the superconductor material used in
cables 722, 724. In some
embodiments, bus bars 726A,B may include carbon nanotube conductors.
As shown in FIGS. 90 and 91, heaters 716A-L are coupled to a single
transformer 728. In certain
embodiments, transformer 728 is a source of time-varying current. In certain
embodiments, transformer 728 is an
electrically isolated, single-phase transformer. In certain embodiments,
transformer 728 provides power to heaters
716A-L from an isolated secondary phase of the transformer. First end portions
of heaters 716A-L may be coupled
to one side of transformer 728 while second end portions of the heaters are
coupled to the opposite side of the
transformer. Transformer 728 provides a substantially common voltage to the
first end portions of heaters 716A-L
and a substantially common voltage to the second end portions of heaters 716A-
L. In certain embodiments,
transformer 728 applies a voltage potential to the first end portions of
heaters 716A-L that is opposite in polarity and
substantially equal in magnitude to a voltage potential applied to the second
end portions of the heaters. For
example, a +660 V potential may be applied to the first end portions of
heaters 716A-L and a -660 V potential
applied to the second end portions of the heaters at a selected point on the
wave of time-varying current (such as AC
or modulated DC). Thus, the voltages at the two end portion of the heaters may
be equal in magnitude and opposite
in polarity with an average voltage that is substantially at ground potential.
Applying the same voltage potentials to the end portions of all heaters 716A-L
produces voltage potentials
along the lengths of the heaters that are substantially the same along the
lengths of the heaters. FIG. 92 depicts a
cross-section representation, along a vertical plane, such as the plane A-A
shown in FIG. 90, of substantially u-
shaped heaters in a hydrocarbon layer. The voltage potential at the cross-
sectional point shown in FIG. 92 along the
length of heater 716A is substantially the same as the voltage potential at
the corresponding cross-sectional points on
heaters 716A-L shown in FIG. 92. At lines equidistant between heater
wellheads, the voltage potential is
approximately zero. Other wells, such as production wells or monitoring wells,
may be located along these zero
voltage potential lines, if desired. Production wells 206 located close to the
overburden may be used to transport
formation fluid that is initially in a vapor phase to the surface. Production
wells located close to a bottom of the
heated portion of the formation may be used to transport formation fluid that
is initially in a liquid phase to the
surface.
In certain embodiments, the voltage potential at the midpoint of heaters 716A-
L is about zero. Having
similar voltage potentials along the lengths of heaters 716A-L inhibits
current leakage between the heaters. Thus,
there is little or no current flow in the formation and the heaters may have
long lengths as described above. Having
the opposite polarity and substantially equal voltage potentials at the end
portions of the heaters also halves the
voltage applied at either end portion of the heater versus having one end
portion of the heater grounded and one end
portion at full potential. Reducing (halving) the voltage potential applied to
an end portion of the heater generally
reduces current leakage, reduces insulator requirements, and/or reduces arcing
distances because of the lower voltage
potential to ground applied at the end portions of the heaters.
In certain embodiments, substantially vertical heaters are used to provide
heat to the formation. Opposite
polarity and substantially equal voltage potentials, as described above, may
be applied to the end portions of the
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substantially vertical heaters. FIG. 93 depicts a side-view representation of
substantially vertical heaters coupled to a
substantially horizontal wellbore. Heaters 716A, 716B, 716C, 716D, 716E, 716F
are located substantially vertical in
hydrocarbon layer 460. First end portions of heaters 716A, 716B, 716C, 716D,
716E, 716F are coupled to bus bar
726A on a surface of the formation. Second end portions of heaters 716A, 7I6B,
716C, 716D, 716E, 716F are
coupled to bus bar 726B in contacting section 642.
Bus bar 726B may be a bus bar located in a substantially horizontal wellbore
in contacting section 642.
Second end portions of heaters 716A, 716B, 716C, 716D, 716E, 716F may be
coupled to bus bar 726B by any
method described herein or any method known in the art. For example,
containers with thermite powder are coupled
to bus bar 726B (for example, by welding or brazing the containers to the bus
bar), end portions of heaters 7I6A,
716B, 716C, 716D, 716E, 716F are placed inside the containers, and the
thermite powder is activated to electrically
couple the heaters to the bus bar. The containers may be coupled to bus bar
726B by, for example, placing the
containers in holes or recesses in bus bar 726B or coupled to the outside of
the bus bar and then brazing or welding
the containers to the bus bar.
Bus bar 726A and bus bar 726B may be coupled to transformer 728 with cables
722, 724, as described
above. Transformer 728 may provide voltages to bar 726A and bus bar 726B as
described above for the
embodiments depicted in FIGS. 90 and 91. For example, transformer 728 may
apply a voltage potential to the first
end portions of heaters 716A-F that is opposite in polarity and substantially
equal in magnitude to a voltage potential
applied to the second end portions of the heaters. Applying the same voltage
potentials to the end portions of all
heaters 716A-F may produce voltage potentials along the lengths of the heaters
that are substantially the same along
the lengths of the heaters. Applying the same voltage potentials to the end
portions of all heaters 716A-F may
inhibit current leakage between the heaters and/or into the formation.
In certain embodiments, it may be advantageous to allow some current leakage
into the formation during
early stages of heating to heat the formation at a faster rate. Current
leakage from the heaters into the formation
electrically heats the formation directly. The formation is heated by direct
electrical heating in addition to
conductive heat provided by the heaters. The formation (the hydrocarbon layer)
may have an initial electrical
resistance that averages at least 10 ohm=m. In some embodiments, the formation
has an initial electrical resistance of
at least 100 ohm=m or of at least 300 ohm.m. Direct electrical heating is
achieved by having opposite potentials
applied to adjacent heaters in the hydrocarbon layer. Current may be allowed
to leak into the formation until a
selected temperature is reached in the heaters or in the formation. The
selected temperature may be below or near
the temperature that water proximate one or more heaters boils off. After
water boils off, the hydrocarbon layer is
substantially electrically isolated from the heaters and direct heating of the
formation is inefficient. After the
selected temperature is reached, the voltage potential is applied in the
opposite polarity and substantially equal
magnitude manner described above for FIGS. 90 and 91 so that adjacent heaters
will have the same voltage potential
along their lengths.
Current is allowed to leak into the formation by reversing the polarity of one
or more heaters shown in FIG.
91 so that a first group of heaters has a positive voltage potential at first
location 646 and a second group of heaters
has a negative voltage potential at the first location. The first end
portions, at first location 646, of a first group of
heaters (for example, heaters 716A, 716B, 716D, 716E, 716G, 716H, 7I6J, 7I6K,
depicted in FIG. 91) are applied
with a positive voltage potential that is substantially equal in magnitude to
a negative voltage potential applied to the
second end portions, at second location 650, of the first group of heaters.
The first end portions, at first location 646,
of the second group of heaters (for example, heaters 716C, 716F, 7161, 716L)
are applied with a negative voltage
potential that is substantially equal in magnitude to the positive voltage
potential applied to the first end portions of
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the first group of heaters. Similarly, the second end portions, at second
location 650, of the second group of heaters
are applied with a positive voltage potential substantially equal in magnitude
to the negative potential applied to the
second end portions of the first group of heaters. After the selected
temperature is reached, the first end portions of
both groups of heaters are applied with voltage potential that is opposite in
polarity and substantially similar in
magnitude to the voltage potential applied to the second end portions of both
groups of heaters.
In some embodiments, heating elements 630 have a thin electrically insulating
layer, described above, to
inhibit current leakage from the heating elements. In some embodiments, the
thin electrically insulating layer is
aluminum oxide or thermal spray coated aluminum oxide. In some embodiments,
the thin electrically insulating
layer is an enamel coating of a ceramic composition. The thin electrically
insulating layer may inhibit heating
elements of a three-phase heater from leaking current between the elements,
from leaking current into the formation,
and from leaking current to other heaters in the formation. Thus, the three-
phase heater may have a longer heater
length.
In certain embodiments, a heater is electrically isolated from the formation
because the heater has little or
no voltage potential on the outside of the heater. FIG. 94 depicts an
embodiment of a substantially u-shaped heater
that electrically isolates itself from the formation. Heater 716 has a first
end portion at a first opening on surface 534
and a second end portion at a second opening on the surface. In some
embodiments, heater 716 has only the first end
portion at the surface with the second end of the heater located in
hydrocarbon layer 460 (the heater is a single-ended
heater). FIGS. 95 and 96 depict embodiments of single-ended heaters that
electrically isolate themselves from the
formation. In certain embodiments, single-ended heater 716 has an elongated
portion that is substantially horizontal
in hydrocarbon layer 460, as shown in FIGS. 95 and 96. In some
embodiments;single-ended heater 716 has an
elongated portion with an orientation other than substantially horizontal in
hydrocarbon layer 460. For example, the
single-ended heater may have an elongated portion that is oriented 15 off
horizontal in the hydrocarbon layer.
As shown in FIGS. 94-96, heater 716 includes heating element 630 located in
hydrocarbon layer 460.
Heating element 630 may be a ferromagnetic conduit heating element or
ferromagnetic tubular heating element. In
certain embodiments, heating element 630 is a temperature limited heater
tubular heating element. In certain
embodiments, heating element 630 is a 9% by weight to 13% by weight chromium
stainless steel tubular such as a
410 stainless steel tubular, a T/P91 stainless steel tubular, or a T/P92
stainless steel tubular. In certain embodiments,
heating element 630 includes ferromagnetic material with a wall thickness of
at least about one skin depth of the
ferromagnetic material at 25 C. In some embodiments, heating element 630
includes ferromagnetic material with a
wall thickness of at least about two times the skin depth of the ferromagnetic
material at 25 C, at least about three
times the skin depth of the ferromagnetic material at 25 C, or at least about
four times the skin depth of the
ferromagnetic material at 25 C.
Heating element 630 is coupled to one or more sections 718. Sections 718 are
located in overburden 458.
Sections 718 include higher electrical conductivity materials such as copper
or aluminum. In certain embodiments,
sections 718 are copper clad inside carbon steel.
Center conductor 730 is positioned inside heating element 630. In some
embodiments, heating element 630
and center conductor 730 are placed or installed in the formation by
unspooling the heating element and the center
conductor from one or more spools while they are placed into the formation. In
some embodiments, heating element
630 and center conductor 730 are coupled together on a single spool and
unspooled as a single system with the
center conductor inside the heating element. In some embodiments, heating
element 630 and center conductor 730
are located on separate spools and the center conductor is positioned inside
the heating element after the heating
element is placed in the formation.
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In certain embodiments, center conductor 730 is located at or near a center of
heating element 630. Center
conductor 730 may be substantially electrically isolated from heating element
630 along a length of the center
conductor (for example, the length of the center conductor in hydrocarbon
layer 460). In certain embodiments,
center conductor 730 is separated from heating element 630 by one or more
electrically-insulating centralizers. The
centralizers may include silicon nitride or another electrically insulating
material. The centralizers may inhibit
electrical contact between center conductor 730 and heating element 630 so
that, for example, arcing or shorting
between the center conductor and the heating element is inhibited. In some
embodiments, center conductor 730 is a
conductor (for example, a solid conductor or a tubular conductor) so that the
heater is in a conductor-in-conduit
configuration.
In certain embodiments, center conductor 730 is a copper rod or copper
tubular. In some embodiments,
center conductor 730 and/or heating element 630 has a thin electrically
insulating layer to inhibit current leakage
from the heating elements. In some embodiments, the thin electrically
insulating layer is aluminum oxide or thermal
spray coated aluminum oxide. In some embodiments, the thin electrically
insulating layer is an enamel coating of a
ceramic composition. The thin electrically insulating layer may inhibit
heating elements of a three-phase heater
from leaking current between the elements, from leaking current into the
formation, and from leaking current to
other heaters in the formation. Thus, the three-phase heater may have a longer
heater length.
In certain embodiments, center conductor 730 is an insulated conductor. The
insulated conductor may
include an electrically conductive core inside an electrically conductive
sheath with electrical insulation between the
core and the sheath. In certain embodiments, the insulated conductor includes
a copper core inside a non-
ferromagnetic stainless steel (for example, 347 stainless steel) sheath with
magnesium oxide insulation between the
core and the sheath. The core may be used to conduct electrical current
through the insulated conductor. In some
embodiments, the insulated conductor is placed inside heating element 630
without centralizers or spacers between
the insulated conductor and the heating element. The sheath and the electrical
insulation of the insulated conductor
may electrically insulate the core from heating element 630 if the center
conductor and the heating element touch.
Thus, the core and heating element 630 are inhibit from electrically shorting
to each other. The insulated conductor
or another solid center conductor 730 may be inhibited from being crushed or
deformed by heating element 630.In
certain embodiments, one end portion of center conductor 730 is electrically
coupled to one end portion of heating
= element 630 at surface 534 using electrical coupling 732, as shown in
FIG. 94. In some embodiments, the end of
center conductor 730 is electrically coupled to the end of heating element 630
in hydrocarbon layer 460 using
electrical coupling 732, as shown in FIGS. 95 and 96. Thus, center conductor
730 is electrically coupled to heating
element 630 in a series configuration in the embodiments depicted in FIGS. 94-
96. In certain embodiments, center
conductor 730 is the insulated conductor and the core of the insulated
conductor is electrically coupled to heating
element 630 in the series configuration. Center conductor 730 is a return
electrical conductor for heating element
630 so that current in the center conductor flows in an opposite direction
from current in the heating element (as
represented by arrows 734). The electromagnetic field generated by current
flow in center conductor 730
substantially confines the flow of electrons and heat generation to the inside
of heating element 630 (for example,
the inside wall of the heating element) below the Curie temperature of the
ferromagnetic material in the heating
element. Thus, the outside of heating element 630 is at substantially zero
potential and the heating element is
electrically isolated from the formation and any adjacent heater or heating
element at temperatures below the Curie
temperature of the ferromagnetic material (for example, at 25 C). Having the
outside of heating element 630 at
substantially zero potential and the heating element electrically isolated
from the formation and any adjacent heater
or heating element allows for long length heaters to be used in hydrocarbon
layer 460 without significant electrical
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(current) losses to the hydrocarbon layer. For example, heaters with lengths
of at least about 100 m, at least about
500 m, or at least about 1000 m may be used in hydrocarbon layer 460.
During application of electrical current to heating element 630 and center
conductor 730, heat is generated
by the heater. In certain embodiments, heating element 630 generates a
majority or all of the heat output of the
heater. For example, when electrical current flows through ferromagnetic
material in heating element 630 and
copper or another low resistivity material in center conductor 730, the
heating element generates a majority or all of
the heat output of the heater. Generating a majority of the heat in the outer
conductor (heating element 630) instead
of center conductor 730 may increase the efficiency of heat transfer to the
formation by allowing direct heat transfer
from the heat generating element (heating element 630) to the formation and
may reduce heat losses across heater
716 (for example, heat losses between the center conductor and the outer
conductor if the center conductor is the
heat generating element). Generating heat in heating element 630 instead of
center conductor 730 also increases the
heat generating surface area of heater 716. Thus, for the same operating
temperature of heater 716, more heat can be
provided to the formation using the outer conductor (heating element 630) as
the heat generating element rather than
center conductor 730.
In some embodiments, a fluid flows through heater 716 (represented by arrows
736 in FIGS. 94 and 95) to
preheat the formation and/or to recover heat from the heating element. In the
embodiment depicted in FIG. 94, fluid
flows from one end of heater 716 to the other end of the heater inside and
through heating element 630 and outside
center conductor 730, as shown by arrows 736. In the embodiment depicted in
FIG. 95, fluid flows into heater 716
through center conductor 730, which is a tubular conductor, as shown by arrows
736. Center conductor 730 includes
openings 738 at the end of the center conductor to allow fluid to exit the
center conductor. Openings 738 may be
perforations or other orifices that allow fluid to flow into and/or out of
center conductor 730. Fluid then returns to
the surface inside heating element 630 and outside center conductor 730, as
shown by arrows 736.
Fluid flowing inside heater 716 (represented by arrows 736 in FIGS. 94 and 95)
may be used to preheat the
heater, to initially heat the formation, and/or to recover heat from the
formation after heating is completed for the in
situ heat treatment process. Fluids that may flow through the heater include,
but are not limited to, air, water, steam,
helium, carbon dioxide or other high heat capacity fluids. In some
embodiments, a hot fluid, such as carbon dioxide,
helium, or DOWTHERM (The Dow Chemical Company, Midland, Michigan, U.S.A.),
flows through the tubular
heating elements to provide heat to the formation. The hot fluid may be used
to provide heat to the formation before
electrical heating is used to provide heat to the formation. In some
embodiments, the hot fluid is used to provide
heat in addition to electrical heating. Using the hot fluid to provide heat to
or preheat the formation in addition to
providing electrical heating may be less expensive than using electrical
heating alone to provide heat to the
formation. In some embodiments, water and/or steam flows through the tubular
heating element to recover heat
from the formation after in situ heat treatment of the formation. The heated
water and/or steam may be used for
solution mining and/or other processes.
FIGS. 97A and 97B depict an embodiment for using substantially u-shaped
wellbores to time sequence heat
two layers in a hydrocarbon containing formation. In FIG. 97A, substantially
horizontal opening 522A is formed in
hydrocarbon layer 460A extending from relatively vertical openings 522.
Hydrocarbon layer 460A is separated from
hydrocarbon layer 460B by impermeable zone 740. In certain embodiments,
hydrocarbon layer 460B is an upper
layer or lesser depth layer than hydrocarbon layer 460A. Impermeable zone 740
provides a substantially
impermeable seal for fluid flow between hydrocarbon layer 460A and hydrocarbon
layer 460B. In certain
embodiments (for example, in an oil shale formation), hydrocarbon layer 460A
has a higher richness than
hydrocarbon layer 460B.
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Heating element 630A is placed in opening 522A in hydrocarbon layer 460A.
Overburden casing 530 is
placed along the relatively vertical walls of openings 522 in hydrocarbon
layer 460B. Overburden casing 530
inhibits heat transfer to hydrocarbon layer 460B while heat is provided to
hydrocarbon layer 460A by heating
element 630A. Heating element 630A is used to provide heat to hydrocarbon
layer 460A. Formation fluids, such as
pyrolyzed hydrocarbons, may be produced from hydrocarbon layer 460A.
Heat may be provided to hydrocarbon layer 460A by heating element 630A for a
selected length of time.
The selected length of time may be based on a variety of factors including,
but not limited to, formation
characteristics, present or future economic factors, or capital costs. For
example, for an oil shale formation,
hydrocarbon layer 460A may have a richness of about 0.12 L/kg (30.5 gals/ton)
so the layer is heated for about 25
years. Production of formation fluids from hydrocarbon layer 460A may continue
from the layer until production
slows down to an uneconomical rate.
After hydrocarbon layer 460A is heated for the selected time, heating element
630A is turned off. Heating
element 630A may be pulled firmly (for example, yanked) upwards so that the
heating element breaks off at links
742. Links 742 may be weak links designed to pull apart when a selected or
sufficient amount of pulling force is
applied to the links. The upper portions of heating element 630A are then
pulled out of the formation and the
substantially horizontal portion of heating element 630A is left in opening
522A, as shown in FIG. 97B. In some
embodiments, only one link 742 may be broken so that the upper portion above
the one link can be removed and the
remaining portions of the heater can be removed by pulling on the opposite end
of the heater. Thus, the entire length
of heating element 630A may be removed from the formation.
After upper portions of heating element 630A are removed from openings 522,
plugs 744 may be placed
into openings 522 at a selected location in hydrocarbon layer 460B, as
depicted in FIG. 97B. In certain
embodiments, plugs 744 are placed into openings 522 at or near impermeable
zone 740. Packing 532 may be placed
into openings 522 above plugs 744. In some embodiments, packing 532 is filled
into openings 522 without plugs in
the openings.
After plugs 744 and/or packing 532 is set into place in openings 522,
substantially horizontal opening 522B
may be formed in hydrocarbon layer 460B through casing 530. Heating element
630B is placed into opening 522B.
Heating element 630B is used to provide heat to hydrocarbon layer 460B.
Formation fluids, such as pyrolyzed
hydrocarbons, may be produced from hydrocarbon layer 460B.
Heating hydrocarbon layers 460A, 460B in the time-sequenced manner described
above may be more
economical than producing from only one layer or using vertical heaters to
provide heat to the layers simultaneously.
Using relatively vertical openings 522 to access both hydrocarbon layers at
different times may save on capital costs
associated with forming openings in the formation and providing surface
facilities to power the heating elements.
Heating hydrocarbon layer 460A first before heating hydrocarbon layer 460B may
improve the economics of
treating the formation (for example, the net present value of a project to
treat the formation). In addition,
impermeable zone 740 and packing 532 may provide a seal for hydrocarbon layer
460A after heating and production
from the layer. This seal may be useful for abandonment of the hydrocarbon
layer after treating the hydrocarbon
layer.
In certain embodiments, portions of the wellbore that extend through the
overburden include casings. The
casings may include materials that inhibit inductive effects in the casings.
Inhibiting inductive effects in the casings
may inhibit induced currents in the casing and/or reduce heat losses to the
overburden. In some embodiments, the
overburden casings may include non-metallic materials such as fiberglass,
polyvinylchloride (PVC), chlorinated
PVC (CPVC), high-density polyethylene (HDPE), or other high temperature
plastics. HDPEs with working
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temperatures in a usable range include HDPEs available from Dow Chemical Co.,
Inc. (Midland, Michigan, U.S.A.).
The overburden casings may be made of materials that are spoolable so that the
overburden casings can be spooled
into the wellbore. In some embodiments, overburden casings may include non-
magnetic metals such as aluminum or
non-magnetic alloys such as manganese steels having at least 10% manganese,
iron aluminum alloys with at least
18% aluminum, or austentitic stainless steels such as 304 stainless steel or
316 stainless steel. In some
embodiments, overburden casings may include carbon steel or other
ferromagnetic material coupled on the inside
diameter to a highly conductive non-ferromagnetic metal (for example, copper
or aluminum) to inhibit inductive
effects or skin effects. In some embodiments, overburden casings are made of
inexpensive materials that may left in
the formation (sacrificial casings).
In certain embodiments, wellheads for the wellbores may be made of one or more
non-ferromagnetic
materials. The wellheads may include fiberglass, PVC, CPVC, HDPE, and/or non-
magnetic alloys or metals. Using
non-ferromagnetic materials in the wellhead may inhibit undesired heating of
components in the wellhead.
Ferromagnetic materials used in the wellhead may be electrically and/or
thermally insulated from other components
of the wellhead. In some embodiments, an inert gas (for example, nitrogen or
argon) is purged inside the wellhead
and/or inside of casings to inhibit reflux of heated gases into the wellhead
and/or the casings.
In some embodiments, ferromagnetic materials in the wellhead are electrically
coupled to a non-
ferromagnetic material (for example, copper) to inhibit skin effect heat
generation in the ferromagnetic materials in
the wellhead. The non-ferromagnetic material is in electrical contact with the
ferromagnetic material so that current
flows through the non-ferromagnetic material. For example, copper may be
plasma sprayed, coated, or lined on the
inside and/or outside walls of the wellhead. In some embodiments, a non-
ferromagnetic material such as copper is
welded, brazed, clad, or otherwise electrically coupled to the inside and/or
outside walls of the wellhead. For
example, copper may be swaged out to line the inside walls in the wellhead.
Copper may be liquid nitrogen cooled
and then allowed to expand to contact and swage against the inside walls of
the wellhead. In some embodiments, the
copper is hydraulically expanded to contact against the inside walls of the
wellhead.
In some embodiments, two or more substantially horizontal wellbores are
branched off of a first
substantially vertical wellbore drilled downwards from a first location on a
surface of the formation. The
substantially horizontal wellbores may be substantially parallel through a
hydrocarbon layer. The substantially
horizontal wellbores may reconnect at a second substantially vertical wellbore
drilled downwards at a second
location on the surface of the formation. Having multiple wellbores branching
off of a single substantially vertical
wellbore drilled downwards from the surface reduces the number of openings
made at the surface of the formation.
In certain embodiments, a temperature limited heater is utilized for heavy oil
applications (for example,
treatment of relatively permeable formations or tar sands formations). A
temperature limited heater may provide a
relatively low Curie temperature so that a maximum average operating
temperature of the heater is less than 350 C,
300 C, 250 C, 225 C, 200 C, or 150 C. In an embodiment (for example, for
a tar sands formation), a maximum
temperature of the heater is less than about 250 C to inhibit olefin
generation and production of other cracked
products. In some embodiments, a maximum temperature of the heater above about
250 C is used to produce
lighter hydrocarbon products. For example, the maximum temperature of the
heater may be at or less than about 500
C.
A heater may heat a volume of formation adjacent to a production wellbore (a
near production wellbore
region) so that the temperature of fluid in the production wellbore and in the
volume adjacent to the production
wellbore is less than the temperature that causes degradation of the fluid.
The heat source may be located in the
production wellbore or near the production wellbore. In some embodiments, the
heat source is a temperature limited
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heater. In some embodiments, two or more heat sources may supply heat to the
volume. Heat from the heat source
may reduce the viscosity of crude oil in or near the production wellbore. In
some embodiments, heat from the heat
source mobilizes fluids in or near the production wellbore and/or enhances the
radial flow of fluids to the production
wellbore. In some embodiments, reducing the viscosity of crude oil allows or
enhances gas lifting of heavy oil
(approximately at most 100 API gravity oil) or intermediate gravity oil
(approximately 12 to 20 API gravity oil)
from the production wellbore. In certain embodiments, the initial API gravity
of oil in the formation is at most 100,
at most 20 , at most 25 , or at most 30 . In certain embodiments, the
viscosity of oil in the formation is at least 0.05
Pas (50 cp). In some embodiments, the viscosity of oil in the formation is at
least 0.10 Pas (100 cp), at least 0.15
Pas (150 cp), or at least at least 0.20 Pas (200 cp). Large amounts of natural
gas may have to be utilized to provide
gas lift of oil with viscosities above 0.05 Pas. Reducing the viscosity of oil
at or near the production wellbore in the
formation to a viscosity of 0.05 Pas (50 cp), 0.03 Pas (30 cp), 0.02 Pas (20
cp), 0.01 Pas (10 cp), or less (down to
0.001 Pas (1 cp) or lower) lowers the amount of natural gas needed to lift oil
from the formation. In some
embodiments, reduced viscosity oil is produced by other methods such as
pumping.
The rate of production of oil from the formation may be increased by raising
the temperature at or near a
production wellbore to reduce the viscosity of the oil in the formation in and
adjacent to the production wellbore. In
certain embodiments, the rate of production of oil from the formation is
increased by 2 times, 3 times, 4 times, or
greater up to 20 times over standard cold production, which has no external
heating of formation during production.
Certain formations may be more economically viable for enhanced oil production
using the heating of the near
production wellbore region. Formations that have a cold production rate
approximately between 0.05 m3/(day per
meter of wellbore length) and 0.20 m3/(day per meter of wellbore length) may
have significant improvements in
production rate using heating to reduce the viscosity in the near production
wellbore region. In some formations,
production wells up to 775 m, up to 1000 m, or up to 1500 m in length are
used. For example, production wells
between 450 m and 775 m in length are used, between 550 m and 800 m are used,
or between 650 m and 900 m are
used. Thus, a significant increase in production is achievable in some
formations. Heating the near production
wellbore region may be used in formations where the cold production rate is
not between 0.05 m3/(day per meter of
wellbore length) and 0.20 m3/(day per meter of wellbore length), but heating
such formations may not be as
economically favorable. Higher cold production rates may not be significantly
increased by heating the near
wellbore region, while lower production rates may not be increased to an
economically useful value.
Using the temperature limited heater to reduce the viscosity of oil at or near
the production well inhibits
problems associated with non-temperature limited heaters and heating the oil
in the formation due to hot spots. One
possible problem is that non-temperature limited heaters can causing coking of
oil at or near the production well if
the heater overheats the oil because the heaters are at too high a
temperature. Higher temperatures in the production
well may also cause brine to boil in the well, which may lead to scale
formation in the well. Non-temperature
limited heaters that reach higher temperatures may also cause damage to other
wellbore components (for example,
screens used for sand control, pumps, or valves). Hot spots may be caused by
portions of the formation expanding
against or collapsing on the heater. In some embodiments, the heater (either
the temperature limited heater or
another type of non-temperature limited heater) has sections that are lower
because of sagging over long heater
distances. These lower sections may sit in heavy oil or bitumen that collects
in lower portions of the wellbore. At
these lower sections, the heater may develop hot spots due to coking of the
heavy oil or bitumen. A standard non-
temperature limited heater may overheat at these hot spots, thus producing a
non-uniform amount of heat along the
length of the heater. Using the temperature limited heater may inhibit
overheating of the heater at hot spots or lower
sections and provide more uniform heating along the length of the wellbore.
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In some embodiments, oil or bitumen cokes in a perforated liner or screen in a
heater/production wellbore
(for example, coke may form between the heater and the liner or between the
liner and the formation). Oil or
bitumen may also coke in a toe section of a heel and toe heater/production
wellbore, as shown in and described
below for FIG. 112. A temperature limited heater may limit a temperature of a
heater/production wellbore below a
coking temperature to inhibit coking in the well so that the wellbore does not
plug up.
In certain embodiments, fluids in the relatively permeable formation
containing heavy hydrocarbons are
produced with little or no pyrolyzation of hydrocarbons in the formation. In
certain embodiments, the relatively
permeable formation containing heavy hydrocarbons is a tar sands formation.
For example, the formation may be a
tar sands formation such as the Athabasca tar sands formation in Alberta,
Canada or a carbonate formation such as
the Grosmont carbonate formation in Alberta, Canada. The fluids produced from
the formation are mobilized fluids.
Producing mobilized fluids may be more economical than producing pyrolyzed
fluids from the tar sands formation.
Producing mobilized fluids may also increase the total amount of hydrocarbons
produced from the tar sands
formation.
FIGS. 98-101 depict side view representations of embodiments for producing
mobilized fluids from tar
sands formations. In FIGS. 98-101, heaters 716 have substantially horizontal
heating sections in hydrocarbon layer
460 (as shown, the heaters have heating sections that go into and out of the
page). FIG. 98 depicts a side view
representation of an embodiment for producing mobilized fluids from a tar
sands formation with a relatively thin
hydrocarbon layer. FIG. 99 depicts a side view representation of an embodiment
for producing mobilized fluids
from a thicker hydrocarbon layer (the hydrocarbon layer depicted in FIG. 99 is
thicker than the hydrocarbon layer
depicted in FIG. 98). FIG. 100 depicts a side view representation of an
embodiment for producing mobilized fluids
from an even thicker hydrocarbon layer (the hydrocarbon layer depicted in FIG.
100 is thicker than the hydrocarbon
layer depicted in FIG. 99). FIG. 101 depicts a side view representation of an
embodiment for producing mobilized
fluids from a tar sands formation with a hydrocarbon layer that has a shale
break.
In FIG. 98, heaters 716 are placed in an alternating triangular pattern in
hydrocarbon layer 460. In FIGS.
99, 100, and 101, heaters 716 are placed in an alternating triangular pattern
in hydrocarbon layer 460 that repeats
vertically to encompass a majority or all of the hydrocarbon layer. In FIG.
101, the alternating triangular pattern of
heaters 716 in hydrocarbon layer 460 repeats uninterrupted across shale break
746. In FIGS. 98-101, heaters 716
= may be equidistantly spaced from each other. In the embodiments depicted
in FIGS. 98-101, the number of vertical
rows of heaters 716 depends on factors such as, but not limited to, the
desired spacing between the heaters, the
thickness of hydrocarbon layer 460, and/or the number and location of shale
breaks 746. In some embodiments,
heaters 716 are arranged in other patterns. For example, heaters 716 may be
arranged in patterns such as, but not
limited to, hexagonal patterns, square patterns, or rectangular patterns.
In the embodiments depicted in FIGS. 98-101, heaters 716 provide heat that
mobilizes hydrocarbons
(reduces the viscosity of the hydrocarbons) in hydrocarbon layer 460. In
certain embodiments, heaters 716 provide
heat that reduces the viscosity of the hydrocarbons in hydrocarbon layer 460
below about 0.50 Pas (500 cp), below
about 0.10 Pas (100 cp), or below about 0.05 Pas (50 cp). The spacing between
heaters 716 and/or the heat output
of the heaters may be designed and/or controlled to reduce the viscosity of
the hydrocarbons in hydrocarbon layer
460 to desirable values. Heat provided by heaters 716 may be controlled so
that little or no pyrolyzation occurs in
hydrocarbon layer 460. Superposition of heat between the heaters may create
one or more drainage paths (for
example, paths for flow of fluids) between the heaters. In certain
embodiments, production wells 206A and/or
production wells 206B are located proximate heaters 716 so that heat from the
heaters superimposes over the
production wells. The superimposition of heat from heaters 716 over production
wells 206A and/or production wells
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206B creates one or more drainage paths from the heaters to the production
wells. In certain embodiments, one or
more of the drainage paths converge. For example, the drainage paths may
converge at or near a bottommost heater
and/or the drainage paths may converge at or near production wells 206A and/or
production wells 206B. Fluids
mobilized in hydrocarbon layer 460 tend to flow towards the bottommost heaters
716, production wells 206A and/or
production wells 206B in the hydrocarbon layer because of gravity and the heat
and pressure gradients established
by the heaters and/or the production wells. The drainage paths and/or the
converged drainage paths allow production
wells 206A and/or production wells 206B to collect mobilized fluids in
hydrocarbon layer 460.
In certain embodiments, hydrocarbon layer 460 has sufficient permeability to
allow mobilized fluids to
drain to production wells 206A and/or production wells 206B. For example,
hydrocarbon layer 460 may have a
permeability of at least about 0.1 darcy, at least about 1 darcy, at least
about 10 darcy, or at least about 100 darcy. In
some embodiments, hydrocarbon layer 460 has a relatively large vertical
permeability to horizontal permeability
ratio (Kv/Kh). For example, hydrocarbon layer 460 may have a Kv/Kh ratio
between about 0.01 and about 2, between
about 0.1 and about 1, or between about 0.3 and about 0.7.
In certain embodiments, fluids are produced through production wells 206A
located near heaters 716 in the
lower portion of hydrocarbon layer 460. In some embodiments, fluids are
produced through production wells 206B
= located below and approximately midway between heaters 716 in the lower
portion of hydrocarbon layer 460. At
least a portion of production wells 206A and/or production wells 206B may be
oriented substantially horizontal in
hydrocarbon layer 460 (as shown in FIGS. 98-101, the production wells have
horizontal portions that go into and out
of the page). Production wells 206A and/or 206B may be located proximate lower
portion heaters 716 or the
bottommost heaters.
In some embodiments, production wells 206A are positioned substantially
vertically below the bottommost
heaters in hydrocarbon layer 460. Production wells 206A may be located below
heaters 716 at the bottom vertex of
a pattern of the heaters (for example, at the bottom vertex of the triangular
pattern of heaters depicted in FIGS. 98-
101). Locating production wells 206A substantially vertically below the
bottommost heaters may provide efficient
collection of mobilized fluids in hydrocarbon layer 460.
In certain embodiments, the bottommost heaters are located between about 2 m
and about 10 m from the
bottom of hydrocarbon layer 460, between about 4 m and about 8 m from the
bottom of the hydrocarbon layer, or
between about 5 m and about 7 m from the bottom of the hydrocarbon layer. In
certain embodiments, production
wells 206A and/or production wells 206B are located at a distance from the
bottommost heaters 716 that allows heat
from the heaters to superimpose over the production wells but at a distance
from the heaters that inhibits coking at
the production wells. Production wells 206A and/or production wells 206B may
be located a distance from the
nearest heater (for example, the bottommost heater) of at most % of the
spacing between heaters in the pattern of
heaters (for example, the triangular pattern of heaters depicted in FIGS. 98-
101). In some embodiments, production
wells 206A and/or production wells 206B are located a distance from the
nearest heater of at most %, at most 1/2, or
at most 1/2 of the spacing between heaters in the pattern of heaters. In
certain embodiments, production wells 206A
and/or production wells 206B are located between about 2 m and about 10 m from
the bottommost heaters, between
about 4 m and about 8 m from the bottommost heaters, or between about 5 m and
about 7 m from the bottommost
heaters. Production wells 206A and/or production wells 206B may be located
between about 0.5 m and about 8 m
from the bottom of hydrocarbon layer 460, between about 1 m and about 5 m from
the bottom of the hydrocarbon
layer, or between about 2 m and about 4 m from the bottom of the hydrocarbon
layer.
In some embodiments, at least some production wells 206A are located
substantially vertically below
heaters 716 near shale break 746, as depicted in FIG. 101. Production wells
206A may be located between heaters
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716 and shale break 746 to produce fluids that flow and collect above the
shale break. Shale break 746 may be an
impermeable barrier in hydrocarbon layer 460. In some embodiments, shale break
746 has a thickness between
about 1 m and about 6 m, between about 2 m and about 5 m, or between about 3 m
and about 4 m. Production wells
206A between heaters 716 and shale break 746 may produce fluids from the upper
portion of hydrocarbon layer 460
(above the shale break) and production wells 206A below the bottommost heaters
in the hydrocarbon layer may
produce fluids from the lower portion of the hydrocarbon layer (below the
shale break), as depicted in FIG. 101. In
some embodiments, two or more shale breaks may exist in a hydrocarbon layer.
In such an embodiment, production
wells are placed at or near each of the shale breaks to produce fluids flowing
and collecting above the shale breaks.
In some embodiments, shale break 746 breaks down (is desiccated) as the shale
break is heated by heaters
716 on either side of the shale break. As shale break 746 breaks down, the
permeability of the shale break increases
and the shale break allows fluids to flow through the shale break. Once fluids
are able to flow through shale break
746, production wells above the shale break may not be needed for production
as fluids can flow to production wells
at or near the bottom of hydrocarbon layer 460 and be produced there.
In certain embodiments, the bottommost heaters above shale break 746 are
located between about 2 m and
about 10 m from the shale break, between about 4 m and about 8 m from the
bottom of the shale break, or between
about 5 m and about 7 m from the shale break. Production wells 206A may be
located between about 2 m and about
10 m from the bottommost heaters above shale break 746, between about 4 m and
about 8 m from the bottommost
heaters above the shale break, or between about 5 m and about 7 m from the
bottommost heaters above the shale
break. Production wells 206A may be located between about 0.5 m and about 8 m
from shale break 746, between
about 1 m and about 5 m from the shale break, or between about 2 m and about 4
m from the shale break.
In some embodiments, heat is provided in production wells 206A and/or
production wells 206B, depicted in
FIGS. 98-101. Providing heat in production wells 206A and/or production wells
206B may maintain and/or enhance
the mobility of the fluids in the production wells. Heat provided in
production wells 206A and/or production wells
206B may superpose with heat from heaters 716 to create the flow path from the
heaters to the production wells. In
some embodiments, production wells 206A and/or production wells 206B include a
pump to remove fluids to the
surface of the formation. In some embodiments, the viscosity of fluids (oil)
in production wells 206A and/or
production wells 206B is lowered using heaters and/or diluent injection (for
example, using a conduit in the
production wells for injecting the diluent).
In certain embodiments, in situ heat treatment of the relatively permeable
formation containing
hydrocarbons (for example, the tar sands formation) includes heating the
formation to visbreaking temperatures. For
example, the formation may be heated to temperatures between about 100 C and
260 C, between about 150 C and
about 250 C, or between about 200 C and about 240 C. At visbreaking
temperatures, fluids in the formation have
a reduced viscosity (versus their initial viscosity at ambient formation
temperature) that allows fluids to flow in the
formation. The visbroken fluids may have low API gravities (for example, at
most about 10 , about 12 , or about
15 API gravity).
In some embodiments, heaters in the formation are operated at full power
output to heat the formation to
visbreaking temperatures. Operating at full power may rapidly increase the
pressure in the formation. In certain
embodiments, fluids are produced from the formation to maintain a pressure in
the formation below a selected
pressure as the temperature of the formation increases to visbreaking
temperatures. In some embodiments, the
selected pressure is a fracture pressure of the formation. In certain
embodiments, the selected pressure is between
about 1000 kPa and about 15000 kPa, between about 2000 kPa and about 10000
kPa, or between about 2500 kPa and
about 5000 kPa. The fluids produced from the formation may be visbroken and/or
mobilized fluids. Maintaining the
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pressure as close to the fracture pressure as possible may minimize the number
of production wells needed for
producing fluids from the formation because fluids are more mobile at higher
pressures.
In certain embodiments, after the formation reaches visbreaking temperatures,
the pressure in the formation
is reduced. The pressure may be reduced by producing fluids (for example,
visbroken fluids and/or mobilized fluids)
from the formation. In some embodiments, the pressure is reduced below a
pressure at which fluids coke in the
formation to inhibit coking at pyrolysis temperatures. For example, the
pressure is reduced to a pressure below
about 1000 kPa, below about 800 kPa, or below about 700 kPa. The pressure may
be reduced to inhibit coking of
asphaltenes or other large hydrocarbons in the formation. In some embodiments,
the pressure may be maintained
below a pressure at which water passes through a liquid phase at downhole
(formation) temperatures to inhibit liquid
water and dolomite reactions. After reducing the pressure in the formation,
the temperature may be increased to
pyrolysis temperatures to begin pyrolyzation and/or upgrading of fluids in the
formation. The pyrolyzed and/or
upgraded fluids may be produced from the formation.
The amount of fluids produced at temperatures below visbreaking temperatures,
the amount of fluids
produced at visbreaking temperatures, and the amount of upgraded fluids
produced may be varied to control the
quality and amount of fluids produced from the formation and the total
recovery of hydrocarbons from the
formation. For example, producing more fluid during the early stages of
treatment (for example, producing at
temperatures below visbreaking temperatures) may increase the total recovery
of hydrocarbons from the formation
while reducing the overall quality (lowering the overall API gravity) of fluid
produced from the formation. The
overall quality is reduced because more heavy hydrocarbons are produced by
producing more fluids at the lower
temperatures. Producing less fluids at the lower temperatures may increase the
overall quality of the fluids produced
from the formation but may lower the total recovery of hydrocarbons from the
formation.
In certain embodiments, the formation is heated using isolated cells of
heaters (cells or sections of the
formation that are not interconnected for fluid flow). The isolated cells may
be created by user larger heater
spacings in the formation. For example, large heater spacings may be used in
the embodiments depicted in FIGS.
98-101. These isolated cells may be produced during early stages of heating
(for example, at temperatures below
visbreaking temperatures). Because the cells are isolated from other cells in
the formation, the pressures in the
isolated cells are high and more liquids are producible from the isolated
cells. Thus, more liquids may be produced
= from the formation and a higher total recovery of hydrocarbons may be
reached. During later stages of heating, the
heat gradient will interconnect the isolated cells and pressures in the
formation will drop.
In certain embodiments, the heat gradient in the formation is modified so that
a gas cap is created at or near
an upper portion of the hydrocarbon layer. For example, the heat gradient made
by heaters 716 depicted in the
embodiments depicted in FIGS. 98-101 may be modified to create the gas cap at
or near overburden 458 of
hydrocarbon layer 460. The gas cap may push or drive liquids to the bottom of
the hydrocarbon layer so that more
liquids may be produced from the formation.
In certain embodiments, fluids produced at temperatures below visbreaking
temperatures and/or fluids
produced at visbreaking temperatures are blended with diluent to produce
fluids with lower viscosities. In some
embodiments, the diluent includes upgraded or pyrolyzed fluids produced from
the formation. In some
embodiments, the diluent includes upgraded or pyrolyzed fluids produced from
another portion of the formation or
another formation. In certain embodiments, the amount of fluids produced at
temperatures below visbreaking
temperatures and/or fluids produced at visbreaking temperatures that are
blended with upgraded fluids from the
formation is adjusted to create a fluid suitable for transportation and/or use
in a refinery. The amount of blending
may be adjusted so that the fluid has chemical and physical stability.
Maintaining the chemical and physical stability
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of the fluid may allow the fluid to be transported, reduce pre-treatment
processes at a refinery and/or reduce or
eliminate the need for adjusting the refinery process to compensate for the
fluid.
In certain embodiments, formation conditions (for example, pressure and
temperature) and/or fluid
production are controlled to produce fluids with selected properties. For
example, formation conditions and/or fluid
production may be controlled to produce fluids with a selected API gravity
and/or a selected viscosity. The selected
API gravity and/or selected viscosity may be produced by combining fluids
produced at different formation
conditions (for example, combining fluids produced at different temperatures
during the treatment as described
above). As an example, formation conditions and/or fluid production may be
controlled to produce fluids with an
API gravity of about 19 and a viscosity of about 0.35 Pas (350 cp) at 19 C.
In some embodiments, formation conditions and/or fluid production is
controlled so that water (for
example, connate water) is recondensed in the treatment area. Recondensing
water in the treatment area keeps the
heat of condensation in the formation. In addition, having liquid water in the
formation may increase mobility of
liquid hydrocarbons (oil) in the formation. Liquid water may wet rock or other
strata in the formation by occupying
pores or corners in the strata and creating a slick surface that moves liquid
hydrocarbons more readily through the
formation.
In certain embodiments, a drive process (for example, a steam injection
process such as cyclic steam
injection, a steam assisted gravity drainage process (SAGD), a solvent
injection process, or a carbon dioxide
injection process) is used to treat the tar sands formation in addition to the
in situ heat treatment process. In some
embodiments, heaters are used to create high permeability zones (or injection
zones) in the formation for the drive
process. Heaters may be used to create a mobilization geometry or production
network in the 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 heaters and production wells for the drive process. In some
embodiments, the heaters are used to
provide heat during the drive process. The amount of heat provided by the
heaters may be small compared to the
heat input from the drive process (for example, the heat input from steam
injection).
In some embodiments, the in situ heat treatment process may provide less heat
to the formation (for
example, use a wider heat spacing) if the in situ heat treatment process is
followed by the drive process. The drive
process may be used to increase the amount of heat provided to the formation
to compensate for the loss of heat
injection.
In some embodiments, the drive process is used to treat the formation and
produce hydrocarbons from the
formation. The drive process may recover a low amount of oil in place from the
formation (for example, less than
20% recovery of oil in place from the formation). The in situ heat treatment
process may be used following the drive
process to increase the recovery of oil in place from the formation. In some
embodiments, the drive process preheats
the formation for the in situ heat treatment process. In some embodiments, the
formation is treated using the in situ
heat treatment process a significant time after the formation has been treated
using the drive process. For example,
the in situ heat treatment process is used 1 year, 2 years, or 3 years after a
formation has been treated using the drive
process. The in situ heat treatment process may be used on formations that
have been left dormant after the drive
process treatment because further hydrocarbon production using the drive
process is not possible and/or not
economically feasible on the formation. In some embodiments, the formation
remains at least somewhat preheated
from the drive process even after the significant time.
In some embodiments, heaters are used to preheat the formation for the drive
process. For example, heaters
may be used to create injectivity in the formation for a drive fluid. The
heaters may create high permeability zones
(or injection zones) in the formation for the drive process. In certain
embodiments, heaters are used to create
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injectivity in formations with little or no initial injectivity (for example,
karsted formations such as the Grosmont
formation in Alberta, Canada). Heating the formation may create a mobilization
geometry or production network in
the formation to allow fluids to flow through the formation for the drive
process. For example, heaters may be used
to create a fluid production network between a horizontal heater and a
vertical production well. The heaters used to
preheat the formation for the drive process may also be used to provide heat
during the drive process.
FIG. 102 depicts a top view representation of an embodiment for preheating
using heaters for the drive
process. Injection wells 748 and production wells 206 are substantially
vertical wells. Heaters 716 are long
substantially horizontal heaters positioned so that the heaters pass in the
vicinity of injection wells 748. Heaters 716
intersect the vertical well patterns slightly displaced from the vertical
rows.
The vertical location of heaters 716 with respect to injection wells 748 and
production wells 206 depends
on, for example, the vertical permeability of the formation. In formations
with at least some vertical permeability,
injected steam will rise to the top of the permeable layer in the formation.
In such formations, heaters 716 may be
located near the bottom of hydrocarbon layer 460, as shown in FIG. 103. In
formations with very low vertical
permeabilities, more than one horizontal heater may be used with the heaters
stacked substantially vertically or with
heaters at varying depths in the hydrocarbon layer (for example, heater
patterns as shown in FIGS. 98-101). The
vertical spacing between the horizontal heaters in such formations may
correspond to the distance between the
heaters and the injection wells. Heaters 716 are located in the vicinity of
injection wells 748 and/or production wells
206 so that sufficient energy is delivered by the heaters to provide flow
rates for the drive process that are
economically viable. The spacing between heaters 716 and injection wells 748
or production wells 206 may be
varied to provide an economically viable drive process. The amount of
preheating may also be varied to provide an
economically viable process.
Some embodiments of formations with little or no initial injectivity (such as
karsted formations or karsted
layers in formations) may have tight vugs in one or more layers of the
formations. The tight vugs may be vugs filled
with viscous fluids such as bitumen or heavy oil. In some embodiments, the
vugs have a porosity of at least about 20
porosity units, at least about 30 porosity units, or at least about 35
porosity units. The formation may have a porosity
of at most about 15 porosity units, at most about 10 porosity units, or at
most about 5 porosity units. The tight vugs
inhibit steam or other fluids from being injected into the formation or the
layers with tight vugs. In certain
embodiments, the karsted formation or karsted layers of the formation are
treated using the in situ heat treatment
process. Heating of these formations or layers may decrease the viscosity of
the fluids in the tight vugs and allow
the fluids to drain (for example, mobilize the fluids).
In certain embodiments, only the karsted layers of the formation are treated
using the in situ heat treatment
process. Other non-karsted layers of the formation may be used as seals for
the in situ heat treatment process. For
example, in the Grosmont formation, the Grosmont 3 layer may be used as a
bottom seal for in situ heat treatment of
the Nisku and upper Ireton layers.
In some embodiments, the drive process is used after the in situ heat
treatment of the karsted formation or
karsted layers. In some embodiments, heaters are used to preheat the karsted
formation or karsted layers to create
injectivity in the formation.
In certain embodiments, the karsted formation or karsted layers are heated to
temperatures below the
decomposition temperature of rock (for example, dolomite) in the formation
(for example, temperatures at most
about 407 C). In some embodiments, the karsted formation or karsted layers
are heated to temperatures above the
decomposition temperature of dolomite in the formation. At temperatures above
the dolomite decomposition
temperature, the dolomite may decompose to produce carbon dioxide. The
decomposition of the dolomite and the
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carbon dioxide production may create permeability in the formation and
mobilize viscous fluids in the formation. In
some embodiments, the produced carbon dioxide is maintained in the formation
to produce a gas cap in the
formation. The carbon dioxide may be allowed to rise to the upper portions of
the karsted layers to produce the gas
cap.
In some embodiments, heaters are used to produce and/or maintain the gas cap
in the formation for the in
situ heat treatment process and/or the drive process. The gas cap may drive
fluids from upper portions to lower
portions of the formation and/or from portions of the formation towards
portions of the formation at lower pressures
(for example, portions with production wells). In some embodiments, little or
no heating is provided in the portions
of the formation with the gas cap. In some embodiments, heaters in the gas cap
are turned down and/or off after
formation of the gas cap. Using less heating in the gas cap may reduce the
energy input into the formation and
increase the efficiency of the in situ heat treatment process and/or the drive
process. In some embodiments,
production wells and/or heater wells that are located in the gas cap portion
of the formation may be used for injection
of fluid (for example, steam) to maintain the gas cap.
In some embodiments, the production front of the drive process follows behind
the heat front of the in situ
heat treatment process. In some embodiments, areas behind the production front
are further heated to produce more
fluids from the formation. Further heating behind the production front may
also maintain the gas cap behind the
production front and/or maintain quality in the production front of the drive
process.
In certain embodiments, the drive process is used before the in situ heat
treatment of the formation. In
some embodiments, the drive process is used to mobilize fluids in a first
section of the formation. The mobilized
fluids may then be pushed into a second section by heating the first section
with heaters. Fluids may be produced
from the second section. In some embodiments, the fluids in the second section
are pyrolyzed and/or upgraded using
the heaters.
In some embodiments, the drive process is used to create a "gas cushion" or
pressure sink before the in situ
heat treatment process in formations with low permeabilities. The gas cushion
may be created by fracturing the
formation during the drive process. The gas cushion may inhibit pressures from
increasing to quickly to fracture
pressure during the in situ heat treatment process. The gas cushion may
provide a path for gases to escape or travel
during early stages of heating during the in situ heat treatment process.
In some embodiments, the drive process (for example, the steam injection
process) is used to mobilize
fluids before the in situ heat treatment process. Steam injection may be used
to get hydrocarbons (oil) away from
rock or other strata in the formation. The steam injection may mobilize the
oil without heating the rock.
In some embodiments, injection of a fluid (for example, steam or carbon
dioxide) may consume heat in the
formation and cool the formation depending on the pressure in the formation.
In some embodiments, the injected
fluid is used to recover heat from the formation. The recovered heat may be
used in surface processing of fluids
and/or to preheat other portions of the formation using the drive process.
FIG. 104 depicts a representation of an embodiment for producing hydrocarbons
from a hydrocarbon
containing formation (for example, a tar sands formation). Hydrocarbon layer
460 includes one or more portions
with heavy hydrocarbons. Hydrocarbons may be produced from hydrocarbon layer
460 using more than one
process. In certain embodiments, hydrocarbons are produced from a first
portion of hydrocarbon layer 460 using a
steam injection process (for example, cyclic steam injection or steam-assisted
gravity drainage) and a second portion
of the hydrocarbon layer using an in situ heat treatment process. In the steam
injection process, steam is injected
into the first portion of hydrocarbon layer 460 through injection well 748.
First hydrocarbons are produced from the
first portion through production well 206A. The first hydrocarbons include
hydrocarbons mobilized by the injection
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of steam. In certain embodiments, the first hydrocarbons have an API gravity
of at most 15 , at most 100, at most 8 ,
or at most 6 .
Heaters 716 are used to heat the second portion of hydrocarbon layer 460 to
mobilization, visbreaking,
and/or pyrolysis temperatures. Second hydrocarbons are produced from the
second portion through production well
206B. In some embodiments, the second hydrocarbons include at least some
pyrolyzed hydrocarbons. In certain
embodiments, the second hydrocarbons have an API gravity of at least 15 , at
least 20 , or at least 25 .
In some embodiments, the first portion of hydrocarbon layer 460 is treated
using heaters after the steam
injection process. Heaters may be used to increase the temperature of the
first portion and/or treat the first portion
using an in situ heat treatment process. Second hydrocarbons (including at
least some pyrolyzed hydrocarbons) may
be produced from the first portion through production well 206A.
In some embodiments, the second portion of hydrocarbon layer 460 is treated
using the steam injection
process before using heaters 716 to treat the second portion. The steam
injection process may be used to produce
some fluids (for example, first hydrocarbons or hydrocarbons mobilized by the
steam injection) through production
well 206B from the second portion and/or preheat the second portion before
using heaters 716. In some
embodiments, the steam injection process may be used after using heaters 716
to treat the first portion and/or the
second portion.
Producing hydrocarbons through both processes increases the total recovery of
hydrocarbons from
hydrocarbon layer 460 and may be more economical than using either process
alone. In some embodiments, the first
portion is treated with the in situ heat treatment process after the steam
injection process is completed. For example,
after the steam injection process no longer produces viable amounts of
hydrocarbon from the first portion, the in situ
heat treatment process may be used on the first portion.
Steam is provided to injection well 748 from facility 750. Facility 750 is a
steam and electricity
cogeneration facility. Facility 750 may burn hydrocarbons in generators to
make electricity. Facility 750 may burn
gaseous and/or liquid hydrocarbons to make electricity. The electricity
generated is used to provide electrical power
for heaters 716. Waste heat from the generators is used to make steam. In some
embodiments, some of the
hydrocarbons produced from the formation are used to provide gas for heaters
716, if the heaters utilize gas to
provide heat to the formation. The amount of electricity and steam generated
by facility 750 may be controlled to
vary the production rate and/or quality of hydrocarbons produced from the
first portion and/or the second portion of
hydrocarbon layer 460. The production rate and/or quality of hydrocarbons
produced from the first portion and/or
the second portion may be varied to produce a selected API gravity in a
mixture made by blending the first
hydrocarbons with the second hydrocarbons. The first hydrocarbon and the
second hydrocarbons may be blended
after production to produce the selected API gravity. The production from the
first portion and/or the second portion
may be varied in response to changes in the marketplace for either first
hydrocarbons, second hydrocarbons, and/or a
mixture of the first and second hydrocarbons.
First hydrocarbons produced from production well 206A and/or second
hydrocarbons produced from
production well 206B may be used as fuel for facility 750. In some
embodiments, first hydrocarbons and/or second
hydrocarbons are treated (for example, removing undesirable products) before
being used as fuel for facility 750.
The amount of first hydrocarbons and second hydrocarbons used as fuel for
facility 750 may be determined, for
example, by economics for the overall process, the marketplace for either
first or second hydrocarbons, availability
of treatment facilities for either first or second hydrocarbons, and/or
transportation facilities available for either first
or second hydrocarbons. In some embodiments, most or all the hydrocarbon gas
produced from hydrocarbon layer
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460 is used as fuel for facility 750. Burning all the hydrocarbon gas in
facility 750 eliminates the need for treatment
and/or transportation of gases produced from hydrocarbon layer 460.
The produced first hydrocarbons and the second hydrocarbons may be treated
and/or blended in facility
752. In some embodiments, the first and second hydrocarbons are blended to
make a mixture that is transportable
through a pipeline. In some embodiments, the first and second hydrocarbons are
blended to make a mixture that is
useable as a feedstock for a refinery. The amount of first and second
hydrocarbons produced may be varied based
on changes in the requirements for treatment and/or blending of the
hydrocarbons. In some embodiments, treated
hydrocarbons are used in facility 750.
FIG. 105 depicts an embodiment for heating and producing from the formation
with the temperature limited
heater in a production wellbore. Production conduit 754 is located in wellbore
756. In certain embodiments, a
portion of wellbore 756 is located substantially horizontally in formation
758. In some embodiments, the wellbore is
located substantially vertically in the formation. In an embodiment, wellbore
756 is an open wellbore (an uncased
wellbore). In some embodiments, the wellbore has a casing or liner with
perforations or openings to allow fluid to
flow into the wellbore.
Conduit 754 may be made from carbon steel or more corrosion resistant
materials such as stainless steel.
Conduit 754 may include apparatus and mechanisms for gas lifting or pumping
produced oil to the surface. For
example, conduit 754 includes gas lift valves used in a gas lift process.
Examples of gas lift control systems and
valves are disclosed in U.S. Patent No. 6,715,550 to Vinegar et al. and U.S.
Patent Application Publication Nos.
2002-0036085 to Bass et al. and 2003-0038734 to Hirsch et al., each of which
is incorporated by reference as if fully
set forth herein. Conduit 754 may include one or more openings (perforations)
to allow fluid to flow into the
production conduit. In certain embodiments, the openings in conduit 754 are in
a portion of the conduit that remains
below the liquid level in wellbore 756. For example, the openings are in a
horizontal portion of conduit 754.
Heater 760 is located in conduit 754, as shown in FIG. 105. In some
embodiments, heater 760 is located
outside conduit 754, as shown in FIG. 106. The heater located outside the
production conduit may be coupled
(strapped) to the production conduit. In some embodiments, more than one
heater (for example, two, three, or four
heaters) are placed about conduit 754. The use of more than one heater may
reduce bowing or flexing of the
production conduit caused by heating on only one side of the production
conduit. In an embodiment, heater 760 is a
temperature limited heater. Heater 760 provides heat to reduce the viscosity
of fluid (such as oil or hydrocarbons) in
and near wellbore 756. In certain embodiments, heater 760 raises the
temperature of the fluid in wellbore 756 up to
a temperature of 250 C or less (for example, 225 C, 200 C, or 150 C).
Heater 760 may be at higher temperatures
(for example, 275 C, 300 C, or 325 C) because the heater provides heat to
conduit 754 and there is some
temperature differential between the heater and the conduit. Thus, heat
produced from the heater does not raise the
temperature of fluids in the wellbore above 250 C.
In certain embodiments, heater 760 includes ferromagnetic materials such as
Carpenter Temperature
Compensator "32", Alloy 42-6, Alloy 52, Invar 36, or other iron-nickel or iron-
nickel-chromium alloys. In certain
embodiments, nickel or nickel-chromium alloys are used in heater 760. In some
embodiments, heater 760 includes a
composite conductor with a more highly conductive material such as copper on
the inside of the heater to improve
the turndown ratio of the heater. Heat from heater 760 heats fluids in or near
wellbore 756 to reduce the viscosity of
the fluids and increase a production rate through conduit 754.
In certain embodiments, portions of heater 760 above the liquid level in
wellbore 756 (such as the vertical
portion of the wellbore depicted in FIGS. 105 and 106) have a lower maximum
temperature than portions of the
heater located below the liquid level. For example, portions of heater 760
above the liquid level in wellbore 756
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may have a maximum temperature of 100 C while portions of the heater located
below the liquid level have a
maximum temperature of 250 C. In certain embodiments, such a heater includes
two or more ferromagnetic
sections with different Curie temperatures to achieve the desired heating
pattern. Providing less heat to portions of
wellbore 756 above the liquid level and closer to the surface may save energy.
In certain embodiments, heater 760 is electrically isolated on the heater's
outside surface and allowed to
move freely in conduit 754. In some embodiments, electrically insulating
centralizers are placed on the outside of
heater 760 to maintain a gap between conduit 754 and the heater.
In some embodiments, heater 760 is cycled (turned on and off) so that fluids
produced through conduit 754
are not overheated. In an embodiment, heater 760 is turned on for a specified
amount of time until a temperature of
fluids in or near wellbore 756 reaches a desired temperature (for example, the
maximum temperature of the heater).
During the heating time (for example, 10 days, 20 days, or 30 days),
production through conduit 754 may be stopped
to allow fluids in the formation to "soak" and obtain a reduced viscosity.
After heating is turned off or reduced,
production through conduit 754 is started and fluids from the formation are
produced without excess heat being
provided to the fluids. During production, fluids in or near wellbore 756 will
cool down without heat from heater
760 being provided. When the fluids reach a temperature at which production
significantly slows down, production
is stopped and heater 760 is turned back on to reheat the fluids. This process
may be repeated until a desired amount
of production is reached. In some embodiments, some heat at a lower
temperature is provided to maintain a flow of
the produced fluids. For example, low temperature heat (for example, 100 C,
125 C, or 150 C) may be provided
in the upper portions of wellbore 756 to keep fluids from cooling to a lower
temperature.
FIG. 107 depicts an embodiment of a heating/production assembly that may be
located in a wellbore for gas
lifting. Heating/production assembly 762 may be located in a wellbore in the
formation (for example, wellbore 756
depicted in FIGS. 105 or 106). Conduit 754 is located inside casing 530. In an
embodiment, conduit 754 is coiled
tubing such as 6 cm diameter coiled tubing. Casing 530 has a diameter between
10 cm and 25 cm (for example, a
diameter of 14 cm, 16 cm, or 18 cm). Heater 760 is coupled to an end of
conduit 754. In some embodiments, heater
760 is located inside conduit 754. In some embodiments, heater 760 is a
resistive portion of conduit 754. In some
embodiments, heater 760 is coupled to a length of conduit 754.
Opening 764 is located at or near a junction of heater 760 and conduit 754. In
some embodiments, opening
764 is a slot or a slit in conduit 754. In some embodiments, opening 764
includes more than one opening in conduit
754. Opening 764 allows production fluids to flow into conduit 754 from a
wellbore. Perforated casing 766 allows
fluids to flow into the heating/production assembly 762. In certain
embodiments, perforated casing 766 is a wire
wrapped screen. In one embodiment, perforated casing 766 is a 9 cm diameter
wire wrapped screen.
Perforated casing 766 may be coupled to casing 530 with packing material 532.
Packing material 532
inhibits fluids from flowing into casing 530 from outside perforated casing
766. Packing material 532 may also be
placed inside casing 530 to inhibit fluids from flowing up the annulus between
the casing and conduit 754. Seal
assembly 768 is used to seal conduit 754 to packing material 532. Seal
assembly 768 may fix a position of conduit
754 along a length of a wellbore. In some embodiments, seal assembly 768
allows for unsealing of conduit 754 so
that the production conduit and heater 760 may be removed from the wellbore.
Feedthrough 770 is used to pass lead-in cable 636 to supply power to heater
760. Lead-in cable 636 may be
secured to conduit 754 with clamp 772. In some embodiments, lead-in cable 636
passes through packing material
532 using a separate feedthrough.
A lifting gas (for example, natural gas, methane, carbon dioxide, propane,
and/or nitrogen) may be provided
to the annulus between conduit 754 and casing 530. Valves 774 are located
along a length of conduit 754 to allow
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gas to enter the production conduit and provide for gas lifting of fluids in
the production conduit. The lifting gas
may mix with fluids in conduit 754 to lower the density of the fluids and
allow for gas lifting of the fluids out of the
formation. In certain embodiments, valves 774 are located in or near the
overburden section of the formation so that
gas lifting is provided in the overburden section. In some embodiments, fluids
are produced through the annulus
between conduit 754 and casing 530 and the lifting gas is supplied through
valves 774.
In an embodiment, fluids are produced using a pump coupled to conduit 754. The
pump may be a
submersible pump (for example, an electric or gas powered submersible pump).
In some embodiments, a heater is
coupled to conduit 754 to maintain the reduced viscosity of fluids in the
conduit and/or the pump.
In certain embodiments, an additional conduit such as an additional coiled
tubing conduit is placed in the
formation. Sensors may be placed in the additional conduit. For example, a
production logging tool may be placed
in the additional conduit to identify locations of producing zones and/or to
assess flow rates. In some embodiments,
a temperature sensor (for example, a distributed temperature sensor, a fiber
optic sensor, and/or an array of
thermocouples) is placed in the additional conduit to determine a subsurface
temperature profile.
Some embodiments of the heating/production assembly are used in a well that
preexists (for example, the
heating/production assembly is retrofitted for a preexisting production well,
heater well, or monitoring well). An
example of the heating/production assembly that may be used in the preexisting
well is depicted in FIG. 108. Some
preexisting wells include a pump. The pump in the preexisting well may be left
in the heating/production well
retrofitted with the heating/production assembly.
FIG. 108 depicts an embodiment of the heating/production assembly that may be
located in the wellbore for
gas lifting. In FIG. 108, conduit 754 is located in outside production conduit
776. In an embodiment, outside
production conduit 776 is 11.4 cm diameter production tubing. Casing 530 has a
diameter of 24.4 cm. Perforated
casing 766 has a diameter of 11.4 cm. Seal assembly 768 seals conduit 754
inside outside production conduit 776.
In an embodiment, pump 778 is a jet pump such as a bottomhole assembly jet
pump.
FIG. 109 depicts another embodiment of a heating/production assembly that may
be located in a wellbore
for gas lifting. Heater 760 is located inside perforated casing 766. Heater
760 is coupled to lead-in cable 636
through a feedthrough in packing material 532. Production conduit 754 extends
through packing material 532.
Pump 778 is located along conduit 754. In certain embodiments, pump 778 is a
jet pump or a bean pump. Valves
774 are located along conduit 754 for supplying lift gas to the conduit.
In some embodiments, heat is inhibited from transferring into conduit 754.
FIG. 110 depicts an
embodiment of conduit 754 and heaters 760 that inhibit heat transfer into the
conduit. Heaters 760 are coupled to
conduit 754. Heaters 760 include ferromagnetic sections 486 and non-
ferromagnetic sections 488. Ferromagnetic
sections 486 provide heat at a temperature that reduces the viscosity of
fluids in or near a wellbore. Non-
ferromagnetic sections 488 provide little or no heat. In certain embodiments,
ferromagnetic sections 486 and non-
ferromagnetic sections 488 are 6 m in length. In some embodiments,
ferromagnetic sections 486 and non-
ferromagnetic sections 488 are between 3 m and 12 m in length, between 4 m and
11 m in length, or between 5 m
and 10 m in length. In certain embodiments, non-ferromagnetic sections 488
include perforations 780 to allow fluids
to flow to conduit 754. In some embodiments, heater 760 is positioned so that
perforations are not needed to allow
fluids to flow to conduit 754.
Conduit 754 may have perforations 780 to allow fluid to enter the conduit.
Perforations 780 coincide with
non-ferromagnetic sections 488 of heater 760. Sections of conduit 754 that
coincide with ferromagnetic sections 486
include insulation conduit 782. Conduit 782 may be a vacuum insulated tubular.
For example, conduit 782 may be
a vacuum insulated production tubular available from Oil Tech Services, Inc.
(Houston, Texas, U.S.A.). Conduit
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782 inhibits heat transfer into conduit 754 from ferromagnetic sections 486.
Limiting the heat transfer into conduit
754 reduces heat loss and/or inhibits overheating of fluids in the conduit. In
an embodiment, heater 760 provides
heat along an entire length of the heater and conduit 754 includes conduit 782
along an entire length of the
production conduit.
In certain embodiments, more than one wellbore 756 is used to produce heavy
oils from a formation using
the temperature limited heater. FIG. 111 depicts an end view of an embodiment
with wellbores 756 located in
hydrocarbon layer 460. Portions of wellbores 756 are placed substantially
horizontally in a triangular pattern in
hydrocarbon layer 460. In certain embodiments, wellbores 756 have a spacing of
30 m to 60 m, 35 m to 55 m, or 40
m to 50 m. Wellbores 756 may include production conduits and heaters
previously described. Fluids may be heated
and produced through wellbores 756 at an increased production rate above a
cold production rate for the formation.
Production may continue for a selected time (for example, 5 years to 10 years,
6 years to 9 years, or 7 years to 8
years) until heat produced from each of wellbores 756 begins to overlap
(superposition of heat begins). At such a
time, heat from lower wellbores (such as wellbores 756 near the bottom of
hydrocarbon layer 460) is continued,
reduced, or turned off while production is continued. Production in upper
wellbores (such as wellbores 756 near the
top of hydrocarbon layer 460) may be stopped so that fluids in the hydrocarbon
layer drain towards the lower
wellbores. In some embodiments, power is increased to the upper wellbores and
the temperature raised above the
Curie temperature to increase the heat injection rate. Draining fluids in the
formation in such a process increases
total hydrocarbon recovery from the formation.
In an embodiment, a temperature limited heater is used in a horizontal
heater/production well. The
temperature limited heater may provide selected amounts of heat to the "toe"
and the "heel" of the horizontal portion
of the well. More heat may be provided to the formation through the toe than
through the heel, creating a "hot
portion" at the toe and a "warm portion" at the heel. Formation fluids may be
formed in the hot portion and
produced through the warm portion, as shown in FIG. 112.
FIG. 112 depicts an embodiment of a heater well for selectively heating a
formation. Heat source 202 is
placed in opening 522 in hydrocarbon layer 460. In certain embodiments,
opening 522 is a substantially horizontal
opening in hydrocarbon layer 460. Perforated casing 766 is placed in opening
522. Perforated casing 766 provides
support that inhibits hydrocarbon and/or other material in hydrocarbon layer
460 from collapsing into opening 522.
Perforations in perforated casing 766 allow for fluid flow from hydrocarbon
layer 460 into opening 522. Heat
source 202 may include hot portion 784. Hot portion 784 is a portion of heat
source 202 that operates at higher heat
output than adjacent portions of the heat source. For example, hot portion 784
may output between 650 W/m and
1650 W/m, 650 W/m and 1500 W/m, or 800 W/m and 1500 W/m. Hot portion 784 may
extend from a "heel" of the
heat source to the "toe" of the heat source. The heel of the heat source is
the portion of the heat source closest to the
point at which the heat source enters a hydrocarbon layer. The toe of the heat
source is the end of the heat source
furthest from the entry of the heat source into the hydrocarbon layer.
In an embodiment, heat source 202 includes warm portion 786. Warm portion 786
is a portion of heat
source 202 that operates at lower heat outputs than hot portion 784. For
example, warm portion 786 may output
between 30 W/m and 1000 W/m, 30 W/m and 750 W/m, or 100 W/m and 750 W/m. Warm
portion 786 may be
located closer to the heel of heat source 202. In certain embodiments, warm
portion 786 is a transition portion (for
example, a transition conductor) between hot portion 784 and overburden
portion 788. Overburden portion 788 is
located in overburden 458. Overburden portion 788 provides a lower heat output
than warm portion 786. For
example, overburden portion 788 may output between 10 W/m and 90 W/m, 15 W/m
and 80 W/m, or 25 W/m and
75 W/m. In some embodiments, overburden portion 788 provides as close to no
heat (0 W/m) as possible to
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overburden 458. Some heat, however, may be used to maintain fluids produced
through opening 522 in a vapor
phase or at elevated temperature in overburden 458.
In certain embodiments, hot portion 784 of heat source 202 heats hydrocarbons
to high enough
temperatures to result in coke 790 forming in hydrocarbon layer 460. Coke 790
may occur in an area surrounding
opening 522. Warm portion 786 may be operated at lower heat outputs so that
coke does not form at or near the
warm portion of heat source 202. Coke 790 may extend radially from opening 522
as heat from heat source 202
transfers outward from the opening. At a certain distance, however, coke 790
no longer forms because temperatures
in hydrocarbon layer 460 at the certain distance will not reach coking
temperatures. The distance at which no coke
forms is a function of heat output (W/m from heat source 202), type of
formation, hydrocarbon content in the
formation, and/or other conditions in the formation.
The formation of coke 790 inhibits fluid flow into opening 522 through the
coking. Fluids in the formation
may, however, be produced through opening 522 at the heel of heat source 202
(for example, at warm portion 786 of
the heat source) where there is little or no coke formation. The lower
temperatures at the heel of heat source 202
reduce the possibility of increased cracking of formation fluids produced
through the heel. Fluids may flow in a
horizontal direction through the formation more easily than in a vertical
direction. Typically, horizontal
permeability in a relatively permeable formation is approximately 5 to 10
times greater than vertical permeability.
Thus, fluids flow along the length of heat source 202 in a substantially
horizontal direction. Producing formation
fluids through opening 522 is possible at earlier times than producing fluids
through production wells in hydrocarbon
layer 460. The earlier production times through opening 522 is possible
because temperatures near the opening
increase faster than temperatures further away due to conduction of heat from
heat source 202 through hydrocarbon
layer 460. Early production of formation fluids may be used to maintain lower
pressures in hydrocarbon layer 460
during start-up heating of the formation. Start-up heating of the formation is
the time of heating before production
begins at production wells in the formation. Lower pressures in the formation
may increase liquid production from
the formation. In addition, producing formation fluids through opening 522 may
reduce the number of production
wells needed in the formation.
In some embodiments, a temperature limited heater positioned in a wellbore
heats steam that is provided to
the wellbore. The heated steam may be introduced into a portion of the
formation. In certain embodiments, the
heated steam may be used as a heat transfer fluid to heat a portion of the
formation. In some embodiments, the
steam is used to solution mine desired minerals from the formation. In some
embodiments, the temperature limited
heater positioned in the wellbore heats liquid water that is introduced into a
portion of the formation.
In an embodiment, the temperature limited heater includes ferromagnetic
material with a selected Curie
temperature. The use of a temperature limited heater may inhibit a temperature
of the heater from increasing beyond
a maximum selected temperature (for example, at or about the Curie
temperature). Limiting the temperature of the
heater may inhibit potential burnout of the heater. The maximum selected
temperature may be a temperature
selected to heat the steam to above or near 100% saturation conditions,
superheated conditions, or supercritical
conditions. Using a temperature limited heater to heat the steam may inhibit
overheating of the steam in the
wellbore. Steam introduced into a formation may be used for synthesis gas
production, to heat the hydrocarbon
containing formation, to carry chemicals into the formation, to extract
chemicals or minerals from the formation,
and/or to control heating of the formation.
A portion of the formation where steam is introduced or that is heated with
steam may be at significant
depths below the surface (for example, greater than about 1000 m, about 2500,
or about 5000 m below the surface).
If steam is heated at the surface of the formation and introduced to the
formation through a wellbore, a quality of the
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heated steam provided to the wellbore at the surface may have to be relatively
high to accommodate heat losses to
the wellbore casing and/or the overburden as the steam travels down the
wellbore. Heating the steam in the wellbore
may allow the quality of the steam to be significantly improved before the
steam is provided to the formation. A
temperature limited heater positioned in a lower section of the overburden
and/or adjacent to a target zone of the
formation may be used to controllably heat steam to improve the quality of the
steam injected into the formation
and/or inhibit condensation along the length of the heater. In certain
embodiments, the temperature limited heater
improves the quality of the steam injected and/or inhibits condensation in the
wellbore for long steam injection
wellbores (especially for long horizontal steam injection wellbores).
A temperature limited heater positioned in a wellbore may be used to heat the
steam to above or near 100%
saturation conditions or superheated conditions. In some embodiments, a
temperature limited heater may heat the
steam so that the steam is above or near supercritical conditions. The static
head of fluid above the temperature
limited heater may facilitate producing 100% saturation, superheated, and/or
supercritical conditions in the steam.
Supercritical or near supercritical steam may be used to strip hydrocarbon
material and/or other materials from the
formation. In certain embodiments, steam introduced into the formation may
have a high density (for example, a
specific gravity of about 0.8 or above). Increasing the density of the steam
may improve the ability of the steam to
strip hydrocarbon material and/or other materials from the formation.
Improved iron, chromium, and nickel alloys containing manganese, copper and
tungsten, in combination
with niobium, carbon and nitrogen, may maintain a finer grain size despite
high temperature solution annealing or
processing. Such behavior may be beneficial in reducing a heat-affected-zone
in welded material. Higher solution-
annealing temperatures are particularly important for achieving the best metal
carbide (MC), nanocarbide. For
example, niobium carbide (NbC) nanocarbide strengthening during high-
temperature creep service, and such effects
are amplified (finer nanocarbide structures that are stable) by compositions
of the improved alloys. Tubing and
canister applications that include the composition of the improved alloys and
are wrought processed result in
stainless steels that may be able to age-harden during service at about 700 C
to about 800 C. Improved alloys may
be able to age-harden even more if the alloys are cold-strained prior to high-
temperature service, but such cold-
prestraining is not necessary for good high temperature properties or age-
hardening. Some prior art alloys, such as
NF709 require cold-prestraining to achieve good high temperature creep
properties, and this is a disadvantage in
particular because after such alloys are welded, the advantages of the cold-
prestraining in the weld heat effected zone
are lost. Cold-prestraining may degrade rather than enhance high-temperature
strength and long-term durability, and
therefore may be limited or not permitted by, for example, construction codes.
The improved alloys described herein
are suitable for low temperature applications, for example, cryogenic
applications. The improved alloys which have
strength and sufficient ductility at temperatures of, for example, -50 C to -
200 C, also retain strength at higher
temperatures than many alloys often used in cryogenic applications, such as
201 LN and YUS130, thus for services
such as liquefied natural gas, where a failure may result in a fire, the
improved alloy would retain strength in the
vicinity of the fire longer than other materials.
An improved alloy composition may include, by weight: about 18% to about 22%
chromium, about 12% to
about 13% nickel, above about 0% to about 4.5% copper (and in some
embodiments, above 3.0% to about 4.5%
copper), about 1% to about 10% manganese, about 0.3% to about 1% silicon,
about 0.5% to about 1% niobium,
about 0.3% to about 1% molybdenum, about 0.08% to about 0.2% carbon, about
0.2% to about 0.5% nitrogen, above
0% to about 2% tungsten, and with the balance being essentially iron (for
example, about 47.8% to about 68.12%
iron and optionally other components). Such an improved alloy may be useful
when processed by hot deformation,
cold deformation, and/or welding into, for example, casings, canisters, or
strength members for heaters. In some
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embodiments, the improved alloy includes, by weight: about 20% chromium, about
3% copper, about 4%
manganese, about 0.3% molybdenum, about 0.77% niobium, about 13% nickel, about
0.5% silicon, about 1%
tungsten, about 0.09% carbon, and about 0.26% nitrogen, with the balance being
essentially iron. In certain
embodiments, the improved alloy includes, by weight: about 19% chromium, about
4.2% manganese, about 0.3%
molybdenum, about 0.8% niobium, about 12.5% nickel, about 0.5% silicon, about
0.09% carbon, about 0.24%
nitrogen by weight with the balance being iron. In some embodiments, improved
alloys may vary an amount of
manganese, amount of nickel, and/or a Mn/Ni ratio to enhance resistance to
high temperature sulfidation, increase
high temperature strength, and/or reduce cost.
Improved wrought alloy compositions may include the compositions described in
the preceding paragraphs,
compositions disclosed in U.S. Patent Application Publication No. 2003/0056860
to Maziasz et al., which is
incorporated by reference herein or similar compositions. The improved wrought
alloy composition may include at
least 3.25% by weight precipitates at 800 C. The improved wrought alloy
composition may have been processed by
aging or hot working and/or by cold working. As a result of such aging or hot
working and/or cold working, the
improved wrought alloy compositions (for example, NbC, Cr-rich M23C6) may
contain nanocarbonitrides
precipitates. Such nanocarbonitride precipitates are not known to be present
in cast compositions such as those
disclosed in U.S. Published Patent Application No. 2003/0056860, and are
believed to formed upon hot working
and/or cold working of the compositions. The nanocarbonitride precipitates may
include particles having
dimensions from about 5 nanometers to about 100 nanometers, from about 10
nanometers to about 90 nanometers, or
from about 20 to about 80 nanometers. These wrought alloys may have
microstructures consisting of at least, but
not limited to, nanocarbides (NbC, Cr-rich M23C6), which form during aging
(stress-free) or creep (stress <0.5 yield
stress (YS)). The microstructures may be a consequence of both the native
alloy composition and the details of the
wrought processing. In solution annealed material, the concentration of such
nanoscale particles may be low. The
nanoscale particles may be affected by solution anneal temperature/time (more
and finer dispersion with longer
anneal above 1150 C) and by cold- or warm- prestrain (cold work) after the
solution anneal treatment. Cold
prestrain may create dislocation networks within the grains that may serve as
nucleation sites for the nanocarbides.
Solution annealed material initially has zero percent cold work. Bending,
stretching, coiling, rolling or swaging may
create, for example 5-15% cold work. The effect of the nanocarbides on yield
strength or creep strength may be to
provide strength based on dislocation-pinning, with more closely-spaced
pinning sites (higher concentration, finer
dispersion) providing more strength (particles are barriers to climb or glide
of dislocations).
The improved wrought alloy may include nanonitrides (for example, NbCrN) in
the matrix together with
nanocarbides, after, for example, being aged for 1000 hours at 800 C. The
NbCr nitrides have been identified using
analytical electron microscopy (AEM) as rich in Nb and Cr, and as the
tetragonal nitride phase by electron
diffraction (both carbides are cubic phases). X-ray energy dispersive
quantitative analysis has shown that for the
improved alloy compositions, these nanoscale nitride particles may have a
composition by weight of: about 63% Nb,
28% Cr, and 6% Fe, with other components being less than 1.5% each. Such NbCr
nitrides were not observed in
aged cast stainless steels with similar compositions, and appear to be a
direct consequence of the wrought
processing. The mixed microstructures of nanocarbides and nanonitrides may be
responsible for the improved
strength of these alloy compositions at elevated temperatures, such as, for
example, 900-1000 C.
In some embodiments, the improved alloys are processed to produce a wrought
material. A 6" inside
diameter, centrifugal cast pipe having a wall thickness of 1.5" may be cast
from the improved alloy. A section may
be removed from the casting and heat treated at least 1250 C for, for
example, about three hours. The heat treated
section may be hot rolled at least 1200 C to a 0.75" thickness, annealed at
least 1200 C for fifteen minutes, and
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then sandblasted. The sandblasted section may be cold rolled to a thickness of
about 0.55". The cold rolled section
may be annealed at least 1250 C for about an hour in, for example, air with
an argon cover, and then given a final
additional heat treatment for about one hour at least 1250 C in air with an
argon blanket. An alternative process
may include any of the following: initially homogenizing the cast plate at a
temperature of at least 1200 C for about
1-1/2 hours; hot rolling at least 1200 C to a 1" thickness; and annealing the
cold-rolled plate for about one hour at
least 1200 C. The improved alloys may be extruded at, for example, about 1200
C, with, for example, a mandrel
diameter of 0.9" and a die diameter of 1.35" to produce good quality tubes.
The wrought material may be welded
by, for example, laser welding or tungsten gas arc welding. Thus, tubes may be
produced by rolling plates and
welding seams.
Annealing the improved alloys at higher temperatures, such as 1250 C, may
improve properties of the
alloys. At a higher temperature, more of the phases go into solution and upon
cooling precipitate into phases that
contribute positively to the properties, such as high temperature creep and
tensile strength. Annealing at
temperatures higher than 1250 C, such as 1300 C may be beneficial. For
example, calculated phase present in the
improved alloys may decrease by 0.08% at 1300 C as opposed to the phase
present in the improved alloys at 1200
C. Thus, upon cooling, more useful precipitates may form by 0.08%. Improved
alloys may have high temperature
creep strengths and tensile strengths that are superior to conventional
alloys. For example, niobium stabilized
stainless steel alloys that include manganese, nitrogen, copper and tungsten
may have high temperature creep
strengths and tensile strengths that are improved, or substantially improved
relative to conventional alloys such as
347H.
Improved alloys may have increased strength relative to standard stainless
steel alloys such as Super 304H
at high temperatures (for example, about 700 C, about 800 C, or above 1000
C). Superior high temperature
creep-rupture strength (for example, creep-rupture strength at about 800 C,
about 900 C or about 1250 C) may be
improved as a result of (a) composition, (b) stable, fine-grain
microstructures induced by high temperature
processing, and (c) age-induced precipitation structures in the improved
alloys. Precipitation structures include, for
example, micro-carbides that strengthen grain boundaries and stable
nanocarbides that strengthen inside the grains.
Presence of phases other than sigma, laves, G, and chi phases contribute to
high temperature properties. Stable
microstructures may be achieved by proper selection of components. High
temperature aging induced or creep-
induced microstructures may have minimal or no intermetallic sigma, laves and
chi phases. Intermetallic sigma, lava
and chi phases may weaken the strength properties of alloys.
At about 800 C, the improved alloys may include at least 3% or at least 3.25%
by weight of microcarbides,
other phases, and/or stable, fine grain microstructure that produce strength.
At about 900 C, the improved alloys
may include, by weight, at least 1.5%, at least 2%, at least 3%, at least
3.5%, or at least 5% microcarbides, other
phases, and/or stable, fine grain microstructure that produce strength. These
values may be higher than the
corresponding values in 347H or Super 304H stainless steel alloys at about 900
C. At about 1250 C improved
alloys may include at least 0.5% by weight micro-carbides, other phases,
and/or stable, fine grain microstructure that
produce strength. The resulting higher weight percent of microcarbides, other
phases, and/or stable, fine grain
microstructure, and the exclusion of sigma and laves phases, may account for
superior high temperature performance
of the improved alloys.
Alloys having similar or superior high temperature performance to the improved
alloys may be derived by
modeling phase behavior at elevated temperatures and selecting compositions
that retain at least 1.5%, at least 2%,
or at least 2.5% by weight of phases other than sigma or laves phases at, for
example, about 900 C. For example, a
stable microstructure may include an amount, by weight, of: niobium that is
nearly ten times the amount of carbon,
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from about 1% to about 12% manganese, and from about 0.15 to about 0.5% of
nitrogen. Copper and tungsten may
be included in the composition to increase the amount of stable
microstructures. The choice of elements for the
improved alloys allows processing by various methods and results in a stable,
fine grain size, even after heat
treatments of at least 1250 C. Many prior art alloys tend to grain coarsen
significantly when annealed at such high
temperatures whereas the improved alloy can be improved by such high
temperature treatment. In some
embodiments, grain size is controlled to achieve desirable high temperature
tensile and creep properties. Stable
grain structure in the improved alloys reduces grain boundary sliding, and may
be a contributing factor for the better
strength relative to commercially available alloys at temperatures above, for
example, about 650 C.
A downhole heater assembly may include 5, 10, 20, 40, or more heaters coupled
together. For example, a
heater assembly may include between 10 and 40 heaters. Heaters in a downhole
heater assembly may be coupled in
series. In some embodiments, heaters in a heater assembly may be spaced from
about 7.6 m to about 30.5 m apart.
For example, heaters in a heater assembly may be spaced about 15 m apart.
Spacing between heaters in a heater
assembly may be a function of heat transfer from the heaters to the formation.
For example, a spacing between
heaters may be chosen to limit temperature variation along a length of a
heater assembly to acceptable limits. A
heater assembly may advantageously provide substantially uniform heating over
a relatively long length of an
= opening in a formation. Heaters in a heater assembly may include, but are
not limited to, electrical heaters (for
example, insulated conductor heaters, conductor-in-conduit heaters, pipe-in-
pipe heaters), flameless distributed
combustors, natural distributed combustors, and/or oxidizers. In some
embodiments, heaters in a downhole heater
assembly may include only oxidizers.
FIG. 113 depicts a schematic of an embodiment of downhole oxidizer assembly
800 including oxidizers
802. In some embodiments, oxidizer assembly 800 may include oxidizers 802 and
nameless distributed combustors.
Oxidizer assembly 800 may be lowered into an opening in a formation and
positioned as desired. In some
embodiments, a portion of the opening in the formation may be substantially
parallel to the surface of the Earth. In
some embodiments, the opening of the formation may be otherwise angled with
respect to the surface of the Earth.
In an embodiment, the opening may include a significant vertical portion and a
portion otherwise angled with respect
to the surface of the Earth. In certain embodiments, the opening may be a
branched opening. Oxidizer assemblies
may branch from common fuel and/or oxidizer conduits in a central portion of
the opening.
Fuel 804 may be supplied to oxidizers 802 through fuel conduit 806. In some
embodiments, the fuel for the
oxidizers may be hydrogen or a high hydrogen content hydrocarbon mixture.
Using hydrogen as the fuel has several
advantages over hydrocarbon fuels. For example, hydrogen is easy to ignite,
oxidizing hydrogen does not result in
the generation of carbon dioxide or other undesired reaction products, and
coking of the fuel line is eliminated.
In some embodiments, the fuel may be methane or natural gas. In some
embodiments, the fuel may be a
mixture of hydrocarbons produced from an in situ heat treatment process. In
certain embodiments, fuel used to
initiate combustion may be enriched to decrease the temperature required for
ignition. In some embodiments,
hydrogen (H2) or other hydrogen rich fluids may be used to enrich fuel
initially supplied to the oxidizers. After
ignition of the oxidizers, enrichment of the fuel may be stopped. In some
embodiments, a portion or portions of fuel
conduit 806 may include a catalytic surface (for example, a catalytic outer
surface) to decrease an ignition
temperature of fuel 804.
Portions of the fuel conduit subjected to high temperatures, may include heat
shielding. The heat shielding
may include an insulative underlayer and a thermally conductive overlayer. The
overlayer may be a ceramic layer.
The underlayer may be a low thermal conductivity ceramic sleeve or coating.
The overlayer may be a high thermal
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conductivity coating. In some embodiments, the fuel line may be positioned in
a conduit. A cooling flow may be
circulated through the space between the fuel line and the conduit.
Oxidizing fluid 808 may be supplied to oxidizer assembly 800 through oxidizer
conduit 810. In some
embodiments, fuel conduit 806 and/or oxidizers 802 may be positioned
concentrically, or substantially
concentrically, in oxidizer conduit 810. In some embodiments, fuel conduit 806
and/or oxidizers 802 may be
arranged other than concentrically with respect to oxidizer conduit 810. In
certain branched opening embodiments,
fuel conduit 806 and/or oxidizer conduit 810 may have a weld or coupling to
allow placement of oxidizer assemblies
800 in branches of the opening.
An ignition source may be positioned in or proximate oxidizers 802 to initiate
combustion. In some
embodiments, an ignition source may heat the fuel and/or the oxidizing fluid
supplied to a particular heater to a
temperature sufficient to support ignition of the fuel. The fuel may be
oxidized with the oxidizing fluid in oxidizers
802 to generate heat. Oxidation products may mix with oxidizing fluid
downstream of the first oxidizer in oxidizer
conduit 810. Exhaust gas 812 may include unreacted oxidizing fluid and
unreacted fuel as well as oxidation
products. In some embodiments, a portion of exhaust gas 812 from a first
oxidizer, may be provided to oxidizers
802 downstream of the first oxidizer. In some embodiments, a portion of
exhaust gas 812 may return to the surface
through outer conduit 814. As the exhaust gas returns to the surface through
outer conduit 814, heat from exhaust
gas 812 may be transferred to the formation. Returning exhaust gas 812 through
outer conduit 814 may provide
substantially uniform heating along oxidizer assembly 800 due to heat from the
exhaust gas integrating with the heat
provided from individual oxidizers of the oxidizer assembly. In some
embodiments, oxidizing fluid 808 may be
introduced through outer conduit 814 and exhaust gas 812 may be returned
through oxidizer conduit 810. In certain
embodiments, heat integration may occur along an extended vertical portion of
an opening.
In some embodiments, the oxidizer assembly may be a heat source used to heat
water or steam. Steam
produced by heat from the oxidizer assembly may be introduced into the
formation. The oxidizer assembly may be
placed in a conduit. The conduit may include critical flow orifices. The
oxidizer may be started. Heat produced by
the oxidizer assembly may be used to heat water introduced into the space
between the oxidizer assembly and the
conduit. Steam produced from the heat may pass through the critical flow
orifices in the conduit into the formation.
Oxidizing fluid supplied to an oxidizer assembly may include, but is not
limited to, air, oxygen enriched air,
and/or hydrogen peroxide. Depletion of oxygen in oxidizing fluid may occur
toward a terminal end of an oxidizer
assembly. In an embodiment, a flow of oxidizing fluid may be increased (for
example, by using compression to
provide excess oxidizing fluid) such that sufficient oxygen is present for
operation of the terminal oxidizer. In some
embodiments, oxidizing fluid may be enriched by increasing an oxygen content
of the oxidizing fluid prior to
introduction of the oxidizing fluid to the oxidizers. Oxidizing fluid may be
enriched by methods including, but not
limited to, adding oxygen to the oxidizing fluid, adding an additional oxidant
such as hydrogen peroxide to the
oxidizing fluid (for example, air) and/or flowing oxidizing fluid through a
membrane that allows preferential
diffusion of oxygen.
For oxidizers that use hydrocarbon fuel, steps may be taken to reduce coking
of fuel in the fuel conduit after
ignition of the oxidizers. For example, steam may be added to the fuel to
inhibit coking in the fuel conduit. In some
embodiments, the fuel may be methane that is mixed with steam in a molar ratio
of up to 1:1. In some embodiments,
coking may be inhibited by decreasing a residence time of fuel in the fuel
conduit. In some embodiments, coking
may be inhibited by insulating portions of the fuel conduit that pass through
high temperature zones proximate
oxidizers.
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If steam is to be added to the fuel, the steam needs to be added at the right
point. If steam is added to the
fuel at the surface, the steam may condense in the fuel line on the way down
to the first oxidizer. The resulting
water may slug into the first oxidizer and flameout the oxidizer. In some
embodiments, a separate water line is used
to introduce water into the fuel line. In an embodiment, the water line is
1/4" tubing that transports softened water to
the fuel line near the first oxidizer. When the oxidizers are first
initialized, coking prevention may not be needed, so
water is not sent through the water line. When the first oxidizer is hot,
water may be sent through the water line to
the fuel line. The water may be introduced into the fuel conduit at a location
where the temperature is about 65 C.
The entrance nozzle, the heat from the first oxidizer and the velocity of the
fuel in the fuel line may atomize or
vaporize the water supplied to the fuel conduit.
During operation, there is enough flow through the oxidizer system to protect
the fuel line from overheating
and to minimize the flame temperature. The openings of the oxidizers are
designed to allow a certain flowrate
through the system that increases as the bypass flow increases. At lower
bypass flows, the amount of gas is
restricted and temperatures may become elevated. At the design bypass flow,
the maximum temperatures are lower,
which may result in no or low amounts of oxides of nitrogen and a low fuel
line temperature.
In some embodiments, opening sizes in the oxidizers and the fuel line pressure
relative to the oxidant line
pressure may be controlled to create a flammable mixture in each oxidizer. The
composition of the fuel may be
controlled to minimize flame temperatures. The composition of the fuel may be
changed by adding diluent such as,
but not limited to, steam and/or nitrogen. Opening sizes, fuel line pressure
and fuel composition allow the flame
region of each oxidizer to remain hot, stable and protected from the bypass
flow around the oxidizers so that the
oxidizers burn out the fuel supplied to the individual oxidizers.
FIG. 114 depicts a perspective view of an embodiment of oxidizer 802 of the
downhole heater assembly
without an igniter. FIG. 115 depicts a schematic representation of oxidizer
802 with igniter 816 positioned in
oxidant line 810. Oxidizer 802 may include mix chamber 818, igniter holder
820, nozzle and flame holder 822, and
heat shield 824. In some embodiments, the flame area in flame holder 822
and/or heat shield 824 may be at a
temperature of about 1100 C. The temperature adjacent to the oxidizer may be
about 700 C. Fuel conduit 806
may pass through oxidizer 802. Fuel conduit 806 may have one or more fuel
openings 826 within mix chamber 818.
Openings 828 allow oxidant to flow into mix chamber 818. Opening 830 allows a
portion of the igniter supported
on igniter holder 820 to pass into oxidizer 802. Heat shield 824 may include
openings 832. Openings 832 may
provide additional oxidant to a flame in heat shield 824. Openings 832 may
stabilize the flame in oxidizer 802 and
moderate the temperature of the flame. The size and/or number of openings 832
may be varied depending on
position of the oxidizer in the oxidizer assembly to moderate the temperature
and ensure fuel combustion. Spacers
834 may be positioned on heat shield 824 to keep oxidizer positioned in the
oxidizer conduit.
In some embodiments, the igniters for the oxidizers include temperature
limited heater elements. When the
oxidizer is operating, the temperature of the oxidizer heats the igniter
element above the Curie temperature of the
igniter element so that skin effect heating goes away and electricity flows
through all or substantially all of the heater
element. If the igniter element temperature is below the Curie temperature of
the igniter element, the electricity
flowing through the igniter element is confined to a certain depth so the
effective resistance of the igniter element
increases. The increase in effective resistance causes resistive heating that
raises the temperature of the igniter
element above the ignition temperature of the fuel and gas mixture for the
oxidizer.
In some embodiments, catalytic igniters may be used. The catalytic igniters
may have long operation life at
high temperatures. Catalytic igniters may enable hot restarts without having
to shut down all flames in the
remaining burners when one or more burners flame out. The amount of hydrogen
can be varied in the fuel supply to
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the catalytic igniters so that fluid flow through the oxidizer system does not
have to be lowered to hit ignition
conditions for a particular oxidizer. Under certain operating conditions, one
or more of the catalytic igniters could
be supplied with fuel so that the igniter is hot to assist combustion in case
an oxidizer becomes weak or troublesome
due to manufacturing or long term degradation of the oxidizer. Use of
catalytic igniters may allow for relatively
simple startups.
In some embodiments, flame stabilizers may be added to the oxidizers. The
flame stabilizers may attach
the flame to the heat shield. The high bypass flow around the oxidizer cools
the heat shield and protects the internals
of the oxidizer from damage. FIGS. 116-120 depict various embodiments of heat
shields 824 with flame stabilizers
836. Flame stabilizer 836 depicted in FIG. 116 is a ring. Flame stabilizer 836
depicted in FIG. 117 is an angled
ring. The rings may amount to up to about 25% annular area blockage. The rings
may establish a recirculation zone
near heat shield 824 and away from the fuel line passing through the center of
the heat shield.
FIG. 118 depicts an embodiment of multiple flame stabilizers 836 in heat
shield 824. Flame shield 824 may
have two or more sets of openings 832 along an axial length of the flame
shield. Rings may be positioned behind
one or more of the sets of openings 832. In some embodiments, adjacent rings
may cause interference. To inhibit
interference, 3 partial rings (each ring being about 1/6 the circumference)
may be evenly space about the
circumference instead of one complete ring. The next set of 3 partial rings
along the axial length of heat shield may
be staggered (for example, the rings may be rotated by 120 relative to the
first set of 3 rings).
FIG. 119 depicts an embodiment of flame stabilizer 836 in heat shield 824.
Flame stabilizer 836 is a ring
that angles over upstream openings 832. Flame stabilizer 836 may divert
incoming fluid flow through openings 832
in an upstream direction. The diverted incoming fluid may set up a flow
condition somewhat analogous to high
swirl recirculation (reverse flow). One or more stagnation zones may develop
where a flame front is stable.
FIG. 120 depicts an embodiment wherein flame stabilizers 836 are rounded
deflectors positioned upstream
of openings 832. The portion of flame stabilizers 836 positioned over the
openings may be cylindrical sections with
the concave portions facing openings 832. Flame stabilizers 836 may divert
incoming fluid flow and allow the flame
root area to develop around the deflectors.
One of more of the oxidizers in an oxidizer assembly may be a catalytic
burner. The catalytic burners may
include a catalytic portion followed by a homogenous portion. Catalytic
burners may be started late in an ignition
sequence, and may ignite without igniters. Oxidant for the catalytic burners
would be sufficiently hot from upstream
burners (for example, the oxidant may be at a temperature of about 370 C if
the fuel is primarily methane) so that a
primary mixture would react over the catalyst in the catalyst portion and
produce enough heat so that exiting
products ignite a secondary mixture in the homogenous portion of the oxidizer.
In some embodiments, the fuel may
include enough hydrogen to allow the needed temperature of the oxidant to be
lower. The catalytic portion of the
catalytic burner may use significantly less fuel than the homogenous portion
so that a significant portion of the heat
of the catalytic burner is produced in the homogenous portion of the burner.
FIG. 121 depicts a cross-sectional representation of catalytic burner 838.
Oxidizer may enter mix chamber
818 through openings 828. Fuel may enter mix chamber 818 from fuel conduit 806
through fuel openings 826'.
Fuel and oxidizer may flow to catalyst 840. Catalyst 840 may include palladium
on a honeycomb ceramic support.
The fuel and oxidant react on catalyst 840 to form hot reaction products. The
hot reaction products may be directed
to heat shield 824. Additional fuel enters heat shield 824 through openings
826" in fuel conduit 806. Additional
oxidant enters heat shield 824 through openings 832. The hot reaction products
generated by catalyst 840 may ignite
fuel and oxidant in autoignition zone 842. Autoignition zone 842 may allow
fuel and oxidant to form main
combustion zone 844.
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In some embodiments a catalytic burner may include an igniter to simplify
startup procedures. FIG. 122
depicts catalytic burner 838 that includes igniter 816. Igniter 816 is
positioned in mix chamber 818. Oxidant enters
mix chamber through openings 828A. Fuel enters the mix chamber from fuel line
through fuel openings 826A. The
fuel input into mixture chamber 818 may be only a small fraction of the fuel
input for catalytic burner 838. Inputs
into mixture chamber 818 may be critical flow orifices to maintain tight
control of the mixture under a wide range of
operating conditions. Igniter 816 raises the temperature of the fuel and
oxidant to combustion temperatures in pre-
heat zone 846. Flame stabilizer 836 may be positioned in mixing chamber 818.
Heat from pre-heat zone 846 and/or
combustion products may heat additional fuel that enters mixing chamber 818
through fuel openings 826B and
additional oxidant that enters the mixing chamber through openings 828B.
Openings 826B and openings 828B may
be upstream of flame stabilizer 836. The additional fuel and oxidant are
heated to a temperature sufficient to support
reaction on catalyst 840.
Heated fuel and oxidant from mixing chamber 818 pass to catalyst 840. The fuel
and oxidant react on
catalyst 840 to form hot reaction products. The hot reaction products may be
directed to heat shield 824. Additional
fuel enters heat shield 824 through openings 826C in fuel conduit 806.
Additional oxidant enters heat shield 824
through openings 832. The hot reaction products generated by catalyst 840 may
ignite fuel and oxidant in
autoignition zone 842. Autoignition zone 842 may allow fuel and oxidant to
form main combustion zone 844.
In some embodiments, all of the oxidizers in the oxidizer assembly are
catalytic burners. In some
embodiments, the first or the first several oxidizers in the oxidizer assembly
are catalytic burners. The oxidant
supplied to these burners may be at a lower temperature than subsequent
burners. Using catalytic burners with
igniters may stabilize the first performance of the first several oxidizers in
the oxidizer assembly. Catalytic burners
may be used in-line with other burners to reduce emissions by allowing lower
flame temperatures while still having
substantially complete combustion.
In some embodiments, a catalytic converter may be positioned at the end of the
oxidizer assembly or in the
exhaust gas return. The catalytic converter may remove unburned hydrocarbons
and/or remaining oxides of nitrogen
or other pollutants. The catalytic converter may benefit from the relatively
high temperature of the exhaust gas. In
some embodiments, catalytic burners in series may be integrated with coupled
catalytic converters to limit undesired
emissions from the oxidizer assembly. In some embodiments, a selectively
permeable material may be used to allow
carbon dioxide or other fluids to be separated from the exhaust gas. The
carbon dioxide may be sequestered in a
spent portion of the formation to sequester the carbon dioxide.
In some embodiments, a flameless distributed combustor may be the front and/or
back burner. Having a
flameless distributed combustor as the front burner may stabilize the front
burner and provide heated oxidant to the
next oxidizer. Having a flameless distributed combustor as the back burner may
ensure that the exhaust is depleted
in case one or more of the oxidizers flame out.
In some embodiments, the igniters may be removable or retractable from the
flame after ignition. The
igniter may be placed in a sheath or pulled back from the flame. Having the
ability to remove or retract the igniters
may extend the life of the igniters and provide for a more reliable system
should one or more of the oxidizers need to
be restarted.
The spacing of the oxidizers in an oxidizer assembly may be varied. The
spacing may be varied to
accommodate rich and lean portions of the formation. In some embodiments, the
heat duty of selected oxidizers may
be increased by using ceramic parts inside the oxidizers. Increasing the heat
duty may simplify the overall design
and/or permit a system with fewer burners.
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In some embodiments, the fuel line may be located adjacent to the oxidizers. A
separate line would need to
be routed from the fuel line to each oxidizer. Air shields would be needed to
shield and stabilize the flame due to the
high gas flow requirements. Also, shielding may be needed to protect oxidizer
components.
In some in situ heat treatment embodiments, a downhole gas turbine is used to
provide a portion of the
electricity for an electric heater. The exhaust from the gas turbine may heat
the formation. The heater may be a
temperature limited heater in a horizontal section of a U-shaped well. In some
embodiments, the substantially
horizontal section of the U-shaped well is over 1000m long, over 1300 m long,
over 1600 m long, or over 1900 m
long.
FIG. 123 depicts a schematic representation of a heating system with a
downhole gas turbine. Gas turbine
848 is placed at or near the transition between overburden 458 and hydrocarbon
layer 460. Gas turbine 848 may
include electrical generator 850 and turbine gas combustor 852. Inlet leg 854
to gas turbine 848 may have a
relatively large diameter. The diameter may be 0.3 m, 0.4 m, 0.5 m or greater.
Oxidant line 856 and fuel line 858
supply gas turbine 848. In some embodiments, fuel line 858 is placed within
oxidant line 856, or the oxidant line is
placed in the fuel line. In some embodiments, the oxidant line is positioned
adjacent to the fuel line. In some
embodiments, inlet oxidant and fuel are used to cool gas turbine 848. Oxidant
may be, but is not limited to, air,
oxygen, or oxygen enriched air.
Electricity provided by electrical generator 850 is directed to temperature
limited heater 860 through lead-in
conductors 862. Lead-in conductors 862 may be insulated conductors. If
electrical generator 850 is not able to
supply enough electricity to temperature limited heater 860 to heat
hydrocarbon layer 460 to a desired temperature,
additional electricity may be supplied to the temperature limited heater
through a conductor placed in inlet leg 850
and electrically coupled to the temperature limited heater.
Exhaust gas from gas turbine 852 passes through tubular 864 to outlet 866. In
an embodiment, the tubular
is 4" stainless steel pipe placed in a 6" wellbore. The exhaust gases heat an
initial section of hydrocarbon layer 460
before the gases become too cool to heat the hydrocarbon layer to the desired
temperature. Temperature limited
heater 860 begins a selected distance from gas turbine 848. The distance may
be 200 m, 150 m, 100 m, or less. Heat
provided to the portion of the formation from gas turbine 848 to temperature
limited heater 860 may come from the
exhaust gases passing through tubular 864. Temperature limited heater 860,
which is at least partially supplied with
electricity generated by gas turbine 848, heats hydrocarbon layer 460 and the
exhaust gases from the gas turbine.
Temperature limited heater 860 may be an insulated conductor heater with a
self-limiting temperature of about 760
C. In some embodiments, temperature limited heater 860 is placed in tubular
864. In other embodiments, the
temperature limited heater is on the outside of the tubular. Temperature
limited heater 860 may end at a selected
horizontal distance from the outlet 866 of the temperature limited heater. The
distance may be 200 m, 150 m, 100
m, or less. The exhaust gases heated by temperature limited heater 860
transfer heat to hydrocarbon layer 460 before
passing through overburden 458 to outlet 866.
Inlets and outlets of the U-shaped wells for heating a portion of the
formation may be placed in alternating
directions in adjacent wells. Alternating inlets and outlets of the U-shaped
wells may allow for uniform heating of
the hydrocarbon layer of the formation.
In some embodiments, a portion of oxidant for gas turbine 848 is routed to the
gas turbine from outlet 866
of an adjacent U-shaped well. The portion of oxidant may be sent to the gas
turbine through a separate line. Using
oxidant from the exit of the adjacent well may allow some of the oxidant
and/or heat from the exiting exhaust gases
to be recovered and utilized. The separate exhaust gas line to the gas turbine
may transfer heat to the main oxidant
line and/or fuel line to the gas turbine.
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Compressors and partial expanders may be located at the surface. Compressed
fuel lines and oxidant lines
extend to gas turbine 848. Generators, burners, and expanders of the gas
turbine may be located at or near the
transition between the overburden and the hydrocarbon layer that is to be
heated. Locating equipment in this manner
may reduce the complexity of the downhole equipment, and reduce pressure drops
for the oxidant going down the
wellbore and the combustion gases going through the heater sections and back
to the surface. The surface expander
for a first well can expand gases from an adjacent well outlet since the
adjacent well outlet is physically closer to the
inlet of the first well than is the outlet of the first well. Moving
compressed fuel and compressed oxidant down to
the gas turbine may result in less pressure drop as compared to having cool
fuel and oxidant travel down to the gas
turbine. Placing gas turbine 848 at or near the transition between overburden
458 and hydrocarbon layer 460 allows
exhaust gas from the gas turbine to heat portions of the formation that are to
be pyrolyzed. Placing the gas turbine
848 at or near the transition between overburden 458 and hydrocarbon layer 460
may eliminate or reduce the amount
of insulation needed between the overburden and inlet leg 854. In some
embodiments, tapered insulation may be
applied at the exit of gas turbine 848 to reduce excess heating of the
formation near the gas turbine.
In some in situ heat treatment process embodiments, a circulation system is
used to heat the formation. The
circulation system may be a closed loop circulation system. FIG. 124 depicts a
schematic representation of a system
for heating a formation using a circulation system. The system may be used to
heat hydrocarbons that are relatively
deep in the ground and that are in formations that are relatively large in
extent. In some embodiments, the
hydrocarbons may be 100 m, 200 m, 300 m or more below the surface. The
circulation system may also be used to
heat hydrocarbons that are not as deep in the ground. The hydrocarbons may be
in formations that extend lengthwise
up to 500 m, 750 m, 1000 m, or more. The circulation system may become
economically viable in formations where
the length of the hydrocarbon containing formation to be treated is long
compared to the thickness of the overburden.
The ratio of the hydrocarbon formation extent to be heated by heaters to the
overburden thickness may be at least 3,
at least 5, or at least 10. The heaters of the circulation system may be
positioned relative to adjacent heaters so that
superposition of heat between heaters of the circulation system allows the
temperature of the formation to be raised
at least above the boiling point of aqueous formation fluid in the formation.
In some embodiments, heaters 760 may be formed in the formation by drilling a
first wellbore and then
drilling a second wellbore that connects with the first wellbore. Piping may
be positioned in the U-shaped wellbore
to form U-shaped heater 760. Heaters 760 are connected to heat transfer fluid
circulation system 868 by piping. Gas
at high pressure may be used as the heat transfer fluid in the closed loop
circulation system. In some embodiments,
the heat transfer fluid is carbon dioxide. Carbon dioxide is chemically stable
at the required temperatures and
pressures and has a relatively high molecular weight that results in a high
volumetric heat capacity. Other fluids
such as steam, air, helium and/or nitrogen may also be used. The pressure of
the heat transfer fluid entering the
formation may be 3000 kPa or higher. The use of high pressure heat transfer
fluid allows the heat transfer fluid to
have a greater density, and therefore a greater capacity to transfer heat.
Also, the pressure drop across the heaters is
less for a system where the heat transfer fluid enters the heaters at a first
pressure for a given mass flow rate than
when the heat transfer fluid enters the heaters at a second pressure at the
same mass flow rate when the first pressure
is greater than the second pressure. In some embodiments, a liquid heat
transfer fluid may be used. The liquid heat
transfer fluid may be a natural or synthetic oil, or other type of high
temperature heat transfer fluid.
Heat transfer fluid circulation system 868 may include heat supply 870, first
heat exchanger 872, second
heat exchanger 874, and compressor 876. Heat supply 870 heats the heat
transfer fluid to a high temperature. Heat
supply 870 may be a furnace, solar collector, chemical reactor, nuclear
reactor, fuel cell exhaust heat, or other high
temperature source able to supply heat to the heat transfer fluid. In the
embodiment depicted in FIG. 124, heat
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supply 870 is a furnace that heats the heat transfer fluid to a temperature in
a range from about 700 C to about 920
C, from about 770 C to about 870 C, or from about 800 C to about 850 C. In
an embodiment, heat supply 870
heats the heat transfer fluid to a temperature of about 820 C. The heat
transfer fluid flows from heat supply 870 to
heaters 760. Heat transfers from heaters 760 to formation 758 adjacent to the
heaters. The temperature of the heat
transfer fluid exiting formation 758 may be in a range from about 350 C to
about 580 C, from about 400 C to
about 530 C, or from about 450 C to about 500 C. In an embodiment, the
temperature of the heat transfer fluid
exiting formation 758 is about 480 C. The metallurgy of the piping used to
form heat transfer fluid circulation
system 868 may be varied to significantly reduce costs of the piping. High
temperature steel may be used from heat
supply 870 to a point where the temperature is sufficiently low so that less
expensive steel can be used from that
point to first heat exchanger 872. Several different steel grades may be used
to form the piping of heat transfer fluid
circulation system 868.
Heat transfer fluid from heat supply 870 of heat transfer fluid circulation
system 868 passes through
overburden 458 of formation 758 to hydrocarbon layer 460. Portions of heaters
760 extending through overburden
458 may be insulated. In some embodiments, the insulation or part of the
insulation is a polyimide insulating
material. Inlet portions of heaters 760 in hydrocarbon layer 460 may have
tapering insulation to reduce overheating
of the hydrocarbon layer near the inlet of the heater into the hydrocarbon
layer.
In some embodiments, the diameter of the pipe in overburden 458 may be smaller
than the diameter of pipe
through hydrocarbon layer 460. The smaller diameter pipe through overburden
458 may allow for less heat transfer
to the overburden. Reducing the amount of heat transfer to overburden 458
reduces the amount of cooling of the
heat transfer fluid supplied to pipe adjacent to hydrocarbon layer 460. The
increased heat transfer in the smaller
diameter pipe due to increased velocity of heat transfer fluid through the
small diameter pipe is offset by the smaller
surface area of the smaller diameter pipe and the decrease in residence time
of the heat transfer fluid in the smaller
diameter pipe.
After exiting formation 758, the heat transfer fluid passes through first heat
exchanger 872 and second heat
exchanger 874 to compressor 876. First heat exchanger 872 transfers heat
between heat transfer fluid exiting
formation 758 and heat transfer fluid exiting compressor 876 to raise the
temperature of the heat transfer fluid that
enters heat supply 870 and reduce the temperature of the fluid exiting
formation 758. Second heat exchanger 874
further reduces the temperature of the heat transfer fluid before the heat
transfer fluid enters compressor 876.
FIG. 125 depicts a plan view of an embodiment of wellbore openings in the
formation that is to be heated
using the circulation system. Heat transfer fluid entries 878 into formation
758 alternate with heat transfer fluid exits
880. Alternating heat transfer fluid entries 878 with heat transfer fluid
exits 880 may allow for more uniform heating
of the hydrocarbons in formation 758.
In some embodiments, piping for the circulation system may allow the direction
of heat transfer fluid flow
through the formation to be changed. Changing the direction of heat transfer
fluid flow through the formation allows
each end of a u-shaped wellbore to initially receive the heat transfer fluid
at the heat transfer fluid's hottest
temperature for a period of time, which may result in more uniform heating of
the formation. The direction of heat
transfer fluid may be changed at desired time intervals. The desired time
interval may be about a year, about six
months, about three months, about two months or any other desired time
interval.
In some embodiments, nuclear energy may be used to heat the heat transfer
fluid used in the circulation
system to heat a portion of the formation. Heat supply 870 in FIG. 124 may be
a pebble bed reactor or other type of
nuclear reactor, such as a light water reactor. The use of nuclear energy
provides a heat source with no carbon
dioxide emissions. Also, the use of nuclear energy can be more efficient
because energy losses resulting from the
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conversion of heat to electricity and electricity to heat are avoided by
directly utilizing the heat produced from the
nuclear reactions without producing electricity.
In some embodiments, a nuclear reactor may heat helium. For example, helium
flows through a pebble bed
reactor, and heat transfers to the helium. The helium may be used as the heat
transfer fluid to heat the formation. In
some embodiments, the nuclear reactor may heat helium, and the helium may be
passed through a heat exchanger to
provide heat to the heat transfer fluid used to heat the formation. The pebble
bed reactor may include a pressure
vessel that contains encapsulated enriched uranium dioxide fuel. Helium may be
used as a heat transfer fluid to
remove heat from the pebble bed reactor. Heat may be transferred in a heat
exchanger from the helium to the heat
transfer fluid used in the circulation system. The heat transfer fluid used in
the circulation system may be carbon
dioxide, a molten salt, or other fluid. Pebble bed reactor systems are
available from PBMR Ltd (Centurion, South
Africa).
FIG. 126 depicts a schematic diagram of a system that uses nuclear energy to
heat treatment area 882. The
system may include helium system gas blower 884, nuclear reactor 886, heat
exchanger units 888, and heat transfer
fluid blower 890. Helium system gas blower 884 may draw heated helium from
nuclear reactor 886 to heat
exchanger units 888. Helium from heat exchanger units 888 may pass through
helium system gas blower 884 to
nuclear reactor 886. Helium from nuclear reactor 886 may be at a temperature
of about 900 C to about 1000 C.
Helium from helium gas blower 884 may be at a temperature of about 500 C to
about 600 C. Heat transfer fluid
blower 890 may draw heat transfer fluid from heat exchanger units 888 through
treatment area 882. Heat transfer
fluid may pass through heat transfer fluid blower 890 to heat exchanger units
888. The heat transfer fluid may be
carbon dioxide. The heat transfer fluid may be at a temperature from about 850
C to about 950 C after exiting heat
exchanger units 888.
In some embodiments, the system may include auxiliary power unit 900. In some
embodiments, auxiliary
power unit 900 generates power by passing the helium from heat exchanger units
888 through a generator to make
electricity. The helium may be sent to one or more compressors and/or heat
exchangers to adjust the pressure and
temperature of the helium before the helium is sent to nuclear reactor 886. In
some embodiments, auxiliary power
unit 900 generates power using a heat transfer fluid (for example, ammonia or
aqua ammonia). Helium from heat
exchanger units 888 is sent to additional heat exchanger units to transfer
heat to the heat transfer fluid. The heat
transfer fluid is taken through a power cycle (such as a Kalina cycle) to
generate electricity. In an embodiment,
nuclear reactor 886 is a 400 MW reactor and auxiliary power unit 900 generates
about 30 MW of electricity.
FIG. 127 depicts a schematic elevational view of an arrangement for an in situ
heat treatment process. U-
shaped wellbores may be formed in the formation to define treatment areas
882A, 882B, 882C, 882D. Additional
treatment areas could be formed to the sides of the shown treatment areas.
Treatment areas 882A, 882B, 882C,
882D may have widths of over 300 m, 500 m, 1000 m, or 1500 m. Well exits and
entrances for the wellbores may
be formed in well openings area 902. Rail lines 904 may be formed along sides
of treatment areas 882.
Warehouses, administration offices and/or spent fuel storage facilities may be
located near ends of rail lines 904.
Facilities 906 may be formed at intervals along spurs of rail lines 904. Each
facility 906 may include a nuclear
reactor, compressors, heat exchanger units and other equipment needed for
circulating hot heat transfer fluid to the
wellbores. Facilities 906 may also include surface facilities for treating
formation fluid produced from the
formation. In some embodiments, heat transfer fluid produced in facility 906'
may be reheated by the reactor in
facility 906" after passing through treatment area 882A. In some embodiments,
each facility 906 is used to provide
hot treatment fluid to wells in one half of the treatment area 882 adjacent to
the facility. Facilities 906 may be
moved by rail to another facility site after production from a treatment area
is completed.
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Circulation systems may be used to heat portions of the formation. Production
wells in the formation are
used to remove produced fluids. After production from the formation has ended,
the circulation system may be used
to recover heat from the formation. FIG. 124 depicts an embodiment of a
circulation system. Heat transfer fluid
may be circulated through heaters 760 after heat supply 870 is disconnected
from the circulation system. The heat
transfer fluid may be a different heat transfer fluid than the heat transfer
fluid used to heat the formation. Heat
transfers from the heated formation to the heat transfer fluid. The heat
transfer fluid may be used to heat another
portion of the formation or the heat transfer fluid may be used for other
purposes. In some embodiments, water is
introduced into heaters 760 to produce steam. In some embodiments, low
temperature steam is introduced into
heaters 760 so that the passage of the steam through the heaters increases the
temperature of the steam. Other heat
transfer fluids including natural or synthetic oils, such as Syltherm oil (Dow
Corning Corporation (Midland,
Michigan, U.S.A.), may be used instead of steam or water.
In some embodiments, the circulation system may be used in conjunction with
electrical heating. In some
embodiments, at least a portion of the pipe in the U-shaped wellbores adjacent
to portions of the formation that are to
be heated is made of a ferromagnetic material. For example, the piping
adjacent to a layer or layers of the formation
to be heated is made of a 9% to 13% chromium steel, such as 410 stainless
steel. The pipe may be a temperature
limited heater when time varying electric current is applied to the piping.
The time varying electric current may
resistively heat the piping, which heats the formation. In some embodiments,
direct electric current may be used to
resistively heat the piping, which heats the formation.
In some embodiments, the circulation system is used to heat the formation to a
first temperature, and
electrical energy is used to maintain the temperature of the formation and/or
heat the formation to higher
temperatures. The first temperature may be sufficient to vaporize aqueous
formation fluid in the formation. The
first temperature may be at most about 200 C, at most about 300 C, at most
about 350 C, or at most about 400 C.
Using the circulation system to heat the formation to the first temperature
allows the formation to be dry when
electricity is used to heat the formation. Heating the dry formation may
minimize electrical current leakage into the
formation.
In some embodiments, the circulation system and electrical heating may be used
to heat the formation to a
first temperature. The formation may be maintained, or the temperature of the
formation may be increased from the
first temperature, using the circulation system and/or electrical heating. In
some embodiments, the formation may be
raised to the first temperature using electrical heating, and the temperature
may be maintained and/or increased using
the circulation system. Economic factors, available electricity, availability
of fuel for heating the heat transfer fluid,
and other factors may be used to determine when electrical heating and/or
circulation system heating are to be used.
In certain embodiments, the portion of heater 760 in hydrocarbon layer 460 is
coupled to lead-in
conductors. Lead-in conductors may be located in overburden 458. Lead-in
conductors may electrically couple the
portion of heater 760 in hydrocarbon layer 460 to one or more wellheads at the
surface. Electrical isolators may be
located at a junction of the portion of heater 760 in hydrocarbon layer 460
with portions of heater 760 in overburden
458 so that the portions of the heater in the overburden are electrically
isolated from the portion of the heater in the
hydrocarbon layer. In some embodiments, the lead-in conductors are placed
inside of the pipe of the closed loop
circulation system. In some embodiments, the lead-in conductors are positioned
outside of the pipe of the closed
loop circulation system. In some embodiments, the lead-in conductors are
insulated conductors with mineral
insulation, such as magnesium oxide. The lead-in conductors may include highly
electrically conductive materials
such as copper or aluminum to reduce heat losses in overburden 458 during
electrical heating.
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In certain embodiments, the portions of heater 760 in overburden 458 may be
used as lead-in conductors.
The portions of heater 760 in overburden 458 may be electrically coupled to
the portion of heater 760 in
hydrocarbon layer 460. In some embodiments, one or more electrically
conducting materials (such as copper or
aluminum) are coupled (for example, cladded or welded) to the portions of
heater 760 in overburden 458 to reduce
the electrical resistance of the portions of the heater in the overburden.
Reducing the electrical resistance of the
portions of heater 760 in overburden 458 reduces heat losses in the overburden
during electrical heating.
In some embodiments, the portion of heater 760 in hydrocarbon layer 460 is a
temperature limited heater
with a self-limiting temperature between about 600 C and about 1000 C. The
portion of heater 760 in hydrocarbon
layer 460 may be a 9% to 13% chromium stainless steel. For example, portion of
heater 760 in hydrocarbon layer
460 may be 410 stainless steel. Time-varying current may be applied to the
portion of heater 760 in hydrocarbon
layer 460 so that the heater operates as a temperature limited heater.
FIG. 128 depicts a side view representation of an embodiment of a system for
heating a portion of a
formation using a circulated fluid system ancUor electrical heating. Wellheads
450 of heaters 760 may be coupled to
heat transfer fluid circulation system 868 by piping. Wellheads 450 may also
be coupled to electrical power supply
system 908. In some embodiments, heat transfer fluid circulation system 868 is
disconnected from the heaters when
electrical power is used to heat the formation. In some embodiments,
electrical power supply system 908 is
disconnected from the heaters when heat transfer fluid circulation system 868
is used to heat the formation.
Electrical power supply system 908 may include transformer 728 and cables 722,
724. In certain
embodiments, cables 722, 724 are capable of carrying high currents with low
losses. For example, cables 722, 724
may be thick copper or aluminum conductors. The cables may also have thick
insulation layers. In some
embodiments, cable 722 and/or cable 724 may be superconducting cables. The
superconducting cables may be
cooled by liquid nitrogen. Superconducting cables are available from
Superpower, Inc. (Schenectady, New York,
U.S.A.). Superconducting cables may minimize power loss and/or reduce the size
of the cables needed to couple
transformer 728 to the heaters. In some embodiments, cables 722, 724 may be
made of carbon nanotubes.
In some embodiments, geothermal energy may be used to heat or preheat a
treatment area of an in situ heat
treatment process or a treatment area to be solution mined. Geothermal energy
may have little or no carbon dioxide
emissions. In some embodiments, hot fluid may be produced from a layer or
layers located below or near the
treatment area. The hot fluid may be steam, water, and/or brine. One or more
of the layers may be geothermally
pressurized geysers. Hot fluid may be pumped from one or more of the layers.
The layer or layers may be 2 km, 4
km, 8 km or more below the surface. The hot fluid may be at a temperature of
over 100 C, over 200 C, or over
300 'C.
The hot fluid may be produced and circulated through piping in the treatment
area to raise the temperature
of the treatment area. In some embodiments, the hot fluid is introduced
directly into the treatment area. In some
embodiments, the hot fluid is circulated through the treatment area or piping
in the treatment area without being
produced to the surface and re-introduced into the treatment area. In some
embodiments, the hot fluid may be
produced from a location near the treatment area. The hot fluid may be
transported to the treatment area. Once
transported to the treatment area, the hot fluid is circulated through piping
in the treatment area or the hot fluid is
introduced directly into the treatment area.
In some embodiments, hot fluid produced from a layer or layers is used to
solution mine minerals from the
formation. The hot fluid may be used to raise the temperature of the formation
to a temperature below the
dissociation temperature of the minerals but to a temperature high enough to
increase the amount of mineral going
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into solution in a first fluid introduced into the formation. The hot fluid
may be introduced directly into the
formation as all or a portion of the first fluid, or the hot fluid may be
circulated through piping in the formation.
In some embodiments, hot fluid produced from a layer or layers may be used to
heat the treatment area
before using electrical energy or other types of heat sources to heat the
treatment area to pyrolysis temperatures. The
hot fluid may not be at a temperature sufficient to raise the temperature of
the treatment area to pyrolysis
temperatures. Using the hot fluid to heat the treatment area before using
electrical heaters or other heat sources to
heat the treatment area to pyrolysis temperatures may reduce energy costs for
the in situ heat treatment process.
In some embodiments, hot dry rock technology may be used to produce steam or
other hot heat transfer
fluid from a deep portion of the formation. Injection wells may be drilled to
a depth where the formation is hot. The
injection wells may be over 2 km, over 4 km, or over 8 km deep. Sections of
the formation adjacent to the bottom
portions of the injection wells may be hydraulically or otherwise fractured to
provide large contact area with the
formation and/or to provide flow paths to heated fluid production wells.
Water, steam and/or other heat transfer
fluid may be introduced into the formation through the injection wells. Heat
transfers to the introduced fluid from
the formation. Steam and/or hot heat transfer fluid may be produced from the
heated fluid production wells. In
some embodiments, the steam and/or hot heat transfer fluid is directed into
the treatment area from the production
wells without first producing the steam and/or hot heat transfer fluid to the
surface. The steam and/or hot heat
transfer fluid may be used to heat a portion of a hydrocarbon containing
formation above the deep hot portion of the
formation.
In some embodiments, steam produced from heated fluid production wells may be
used as the steam for a
drive process (for example, a steam flood process or steam assisted gravity
drainage process). In some
embodiments, steam or other hot heat transfer fluid produced through heated
fluid production wells is passed
through U-shaped wellbores or other types of wellbores to provide initial
heating to the formation. In some
embodiments, cooled steam or water, or cooled heat transfer fluid, resulting
from the use of the steam and/or heat
transfer fluid from the hot portion of the formation may be collected and sent
to the hot portion of the formation to
be reheated.
In certain embodiments, a controlled or staged in situ heating and production
process is used to in situ heat
treat a hydrocarbon containing formation (for example, an oil shale
formation). The staged in situ heating and
production process may use less energy input to produce hydrocarbons from the
formation than a continuous or
batch in situ heat treatment process. In some embodiments, the staged in situ
heating and production process is
about 30% more efficient in treating the formation than the continuous or
batch in situ heat treatment process. The
staged in situ heating and production process may also produce less carbon
dioxide emissions than a continuous or
batch in situ heat treatment process. In certain embodiments, the staged in
situ heating and production process is
used to treat rich layers in the oil shale formation. Treating only the rich
layers may be more economical than
treating both rich layers and lean layers because heat may be wasted heating
the lean layers.
FIG. 129 depicts a top view representation of an embodiment for the staged in
situ heating and producing
process for treating the formation. In certain embodiments, heaters 716 are
arranged in triangular patterns. In other
embodiments, heaters 716 are arranged in any other regular or irregular
patterns. The heater patterns may be divided
into one or more sections 910, 912, 914, 916, and/or 918. The number of
heaters 716 in each section may vary
depending on, for example, properties of the formation or a desired heating
rate for the formation. One or more
production wells 206 may be located in each section 910, 912, 914, 916, and/or
918. In certain embodiments,
production wells 206 are located at or near the centers of the sections. In
some embodiments, production wells 206
are in other portions of sections 910, 912, 914, 916, and 918. Production
wells 206 may be located at other locations
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in sections 910, 912, 914, 916, and/or 918 depending on, for example, a
desired quality of products produced from
the sections and/or a desired production rate from the formation.
In certain embodiments, heaters 716 in one of the sections are turned on while
the heaters in other sections
remain turned off. For example, heaters 716 in section 910 may be turned on
while the heaters in the other sections
are left turned off. Heat from heaters 716 in section 910 may create
permeability, mobilize fluids, and/or pyrolysis
fluids in section 910. While heat is being provided by heaters 716 in section
910, production well 206 in section 912
may be opened to produce fluids from the formation. Some heat from heaters 716
in section 910 may transfer to
section 912 and "pre-heat" section 912. The pre-heating of section 912 may
create permeability in section 912,
mobilize fluids in section 912, and allow fluids to be produced from the
section through production well 206. As
fluids are produced from section 912, the movement of fluids from section 910
to section 912 transfers heat between
the sections. The movement of the hot fluids through the formation increases
heat transfer within the formation.
Allowing hot fluids to flow between the sections uses the energy of the hot
fluids for heating of unheated sections
rather than removing the heat from the formation by producing the hot fluids
directly from section 910. Thus, the
movement of the hot fluids allows for less energy input to get production from
the formation than is required if heat
is provided from heaters 716 in both sections to get production from the
sections.
In some embodiments, section 910 and/or section 912 may be treated prior to
turning on heaters 716 to
increase the permeability in the sections. For example, the sections may be
dewatered to increase the permeability in
the sections. In some embodiments, steam injection or other fluid injection
may be used to increase the permeability
in the sections.
In certain embodiments, after a selected time, heaters 716 in section 912 are
turned on. Turning on heaters
716 in section 912 may provide additional heat to sections 910 and 912 to
increase the permeability, mobility, and/or
pyrolysis of fluids in these sections. In some embodiments, as heaters 716 in
section 912 are turned on, production
in section 912 is turned off (shut down) and production well 206 in section
914 is opened to produce fluids from the
formation. Thus, fluid flow in the formation towards production well 206 in
section 914 and section 914 is heated
by the flow of hot fluids as described above for section 912. In some
embodiments, production well 206 in section
912 may be left open after the heaters are turned on in the section, if
desired. This process may be repeated for
subsequent sections in the formation. For example, after a selected time,
heaters in section 914 may be turned on
and fluids produced from production well 206 in section 916 and so on through
the formation.
In some embodiments, heat is provided by heaters 716 in alternating sections
(for example, sections 910,
914, and 918) while fluids are produced from the sections in between the
heated sections (for example, sections 912
and 916). After a selected time, heaters 716 in the unheated sections
(sections 912 and 916) are turned on and fluids
are produced from one or more of the sections as desired.
In certain embodiments, a smaller heater spacing is used in the staged in situ
heating and producing process
than in the continuous or batch in situ heat treatment processes. For example,
the continuous or batch in situ heat
treatment process may use a heater spacing of about 12 m while the in situ
staged heating and producing process
uses a heater spacing of about 10 m. The staged in situ heating and producing
process may use the smaller heater
spacing because the staged process allows for relatively rapid heating of the
formation and expansion of the
formation.
In some embodiments, the sequence of heated sections begins with the outermost
sections and moves
inwards. For example, for a selected time, heat may be provided by heaters 716
in sections 910 and 918 as fluids are
produced from sections 912 and 916. After the selected time, heaters 716 in
sections 912 and 916 may be turned on
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and fluids are produced from section 914. After another selected amount of
time, heaters 716 in section 914 may be
turned on, if needed.
In certain embodiments, sections 910-918 are substantially equal sized
sections. The size and/or location of
sections 910-918 may vary based on desired heating and/or production from the
formation. For example, simulation
of the staged in situ heating and production process treatment of the
formation may be used to determine the number
of heaters in each section, the optimum pattern of sections and/or the
sequence for heater power up and production
well startup for the staged in situ heating and production process. The
simulation may account for properties such
as, but not limited to, formation properties and desired properties and/or
quality in the produced fluids. In some
embodiments, heaters 716 at the edges of the treated portions of the formation
(for example, heaters 716 at the left
edge of section 910 or the right edge of section 918) may have tailored or
adjusted heat outputs to produce desired
heat treatment of the formation.
In some embodiments, the formation is sectioned into a checkerboard pattern
for the staged in situ heating
and production process. FIG. 130 depicts a top view of rectangular
checkerboard pattern 920 embodiment for the
staged in situ heating and production process. In some embodiments, heaters in
the "A" sections (sections 910A,
912A, 914A, 916A, and 918A) may be turned on and fluids are produced from the
"B" sections (sections 910B,
912B, 9I4B, 916B, and 918B). After the selected time, heaters in the "B"
sections may be turned on. The size
and/or number of "A" and "B" sections in rectangular checkerboard pattern 920
may be varied depending on factors
such as, but not limited to, heater spacing, desired heating rate of the
formation, desired production rate, size of
treatment area, subsurface geomechanical properties, subsurface composition,
and/or other formation properties.
In some embodiments, heaters in sections 910A are turned on and fluids are
produced from sections 910B
and/or sections 912B. After the selected time, heaters in sections 912A may be
turned on and fluids are produced
from sections 912B and/or 914B. After another selected time, heaters in
sections 914A may be turned on and fluids
are produced from sections 914B and/or 916B. After another selected time,
heaters in sections 916A may be turned
on and fluids are produced from sections 9I6B and/or 918B. In some
embodiments, heaters in a "B" section that has
been produced from may be turned on when heaters in the subsequent "A" section
are turned on. For example,
heaters in section 910B may be turned on when the heaters in section 912A are
turned on. Other alternating heater
startup and production sequences may also be contemplated for the in situ
staged heating and production process
embodiment depicted in FIG. 130.
In some embodiments, the formation is divided into a circular, ring, or spiral
pattern for the staged in situ
heating and production process. FIG. 131 depicts a top view of the ring
pattern embodiment for the staged in situ
heating and production process. Sections 910, 912, 914, 916, and 918 may be
treated with heater startup and
production sequences similar to the sequences described above for the
embodiments depicted in FIGS. 129. The
heater startup and production sequences for the embodiment depicted in FIG.
131 may start with section 910 (going
inwards towards the center) or with section 918 (going outwards from the
center). Starting with section 910 may
allow expansion of the formation as heating moves towards the center of the
ring pattern. Shearing of the formation
may be minimized or inhibited because the formation is allowed to expand into
heated and/or pyrolyzed portions of
the formation. In some embodiments, the center section (section 918) is cooled
after treatment.
FIG. 132 depicts a top view of a checkerboard ring pattern embodiment for the
staged in situ heating and
production process. The embodiment depicted in FIG. 132 divides the ring
pattern embodiment depicted in 131 into
a checkerboard pattern similar to the checkerboard pattern depicted in FIG.
130. Sections 910A, 912A, 914A, 916A,
918A, 910B, 912B, 914B, 916B, and 918B, depicted in 132, may be treated with
heater startup and production
sequences similar to the sequences described above for the embodiment depicted
in 130.
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In some embodiments, fluids are injected to drive fluids between sections of
the formation. Injecting fluids
such as steam or carbon dioxide may increase the mobility of hydrocarbons and
may increase the efficiency of the
staged in situ heating and production process. In some embodiments, fluids are
injected into the formation after the
in situ heat treatment process to recover heat from the formation. In some
embodiments, the fluids injected into the
formation for heat recovery include some fluids produced from the formation
(for example, carbon dioxide, water,
and/or hydrocarbons produced from the formation). In some embodiments, the
embodiments depicted in FIGS. 129-
132 are used for in situ solution mining of the formation. Hot water or
another fluid may be used to get permeability
in the formation at low temperatures for solution mining.
In certain embodiments, several rectangular checkerboard patterns (for
example, rectangular checkerboard
pattern 920 depicted in FIG. 130) are used to treat a treatment area of the
formation. FIG. 133 depicts a top view of
a plurality of rectangular checkerboard patterns 920(1-36) in treatment area
882 for the staged in situ heating and
production process. Treatment area 882 may be enclosed by barrier 922. Each of
rectangular checkerboard patterns
920(1-36) may individually be treated according to embodiments described above
for the rectangular checkerboard
patterns.
In certain embodiments, the startup of treatment of rectangular checkerboard
patterns 920(1-36) proceeds in
a sequential process. The sequential process may include starting the
treatment of each of the rectangular
checkerboard patterns one by one sequentially. For example, treatment of a
second rectangular checkerboard pattern
(for example, the onset of heating of the second rectangular checkerboard
pattern) may be started after treatment of a
first rectangular checkerboard pattern and so on. The startup of treatment of
the second rectangular checkerboard
pattern may be at any point in time after the treatment of the first
rectangular checkerboard pattern has begun. The
time selected for startup of treatment of the second rectangular checkerboard
pattern may be varied depending on
factors such as, but not limited to, desired heating rate of the formation,
desired production rate, subsurface
geomechanical properties, subsurface composition, and/or other formation
properties. In some embodiments, the
startup of treatment of the second rectangular checkerboard pattern begins
after a selected amount of fluids have
been produced from the first rectangular checkerboard pattern area or after
the production rate from the first
rectangular checkerboard pattern increases above a selected value or falls
below a selected value.
In some embodiments, the startup sequence for rectangular checkerboard
patterns 920(1-36) is arranged to
minimize or inhibit expansion stresses in the formation. In an embodiment, the
startup sequence of the rectangular
checkerboard patterns proceeds in an outward spiral sequence, as shown by the
arrows in FIG. 133. The outward
spiral sequence proceeds sequentially beginning with treatment of rectangular
checkerboard pattern 920-1, followed
by treatment of rectangular checkerboard pattern 920-2, rectangular
checkerboard pattern 920-3, rectangular
checkerboard pattern 920-4, and continuing the sequence up to rectangular
checkerboard pattern 920-36.
Sequentially starting the rectangular checkerboard patterns in the outwards
spiral sequence may minimize or inhibit
expansion stresses in the formation.
Starting treatment in rectangular checkerboard patterns at or near the center
of treatment area 882 and
moving outwards maximizes the starting distance from barrier 922. Barrier 922
may be most likely to fail when heat
is provided at or near the barrier. Starting treatment/heating at or near the
center of treatment area 882 delays
heating of rectangular checkerboard patterns near barrier 922 until later
times of heating in treatment area 882 or at
or near the end of production from the treatment area. Thus, if barrier 922
does fail, the failure of the barrier occurs
after a significant portion of treatment area 882 has been treated.
Starting treatment in rectangular checkerboard patterns at or near the center
of treatment area 882 and
moving outwards also creates open pore space in the inner portions of the
outward moving startup pattern. The open
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pore space allows portions of the formation being started at later times to
expand inwards into the open pore space
and, for example, minimize shearing in the formation.
In some embodiments, support sections are left between one or more of
rectangular checkerboard patterns
920(1-36). The support sections may be unheated sections that provide support
against geomechanical shifting,
shearing, and/or expansion stress in the formation. In some embodiments, some
heat may be provided in the support
sections. The heat provided in the support sections may be less than heat
provided inside rectangular checkerboard
patterns 920(1-36). In some embodiments, each of the support sections may
include alternating heated and unheated
sections. In some embodiments, fluids are produced from one or more of the
unheated support sections.
In some embodiments, one or more of rectangular checkerboard patterns 920(1-
36) have varying sizes. For
example, the outer rectangular checkerboard patterns (such as rectangular
checkerboard patterns 920(21-26) and
rectangular checkerboard patterns 920(31-36)) may have smaller areas and/or
numbers of checkerboards. Reducing
the area and/or the number of checkerboards in the outer rectangular
checkerboard patterns may reduce expansion
stresses and/or geomechanical shifting in the outer portions of treatment area
882. Reducing the expansion stresses
and/or geomechanical shifting in the outer portions of treatment area 882 may
minimize or inhibit expansion stress
and/or shifting stress on barrier 922.
= During an in situ heat treatment process, some formation fluid may
migrate outwards from the treatment
area. The formation fluid may include benzene and other contaminants. Some
portions of the formation that
contaminants migrate to will be subsequently treated when a new treatment area
is defined and processed using the
in situ heat treatment process. Such contaminants may be removed or destroyed
by the subsequent in situ heat
treatment process. Some areas of the formation to which contaminants migrate
may not be become part of a new
treatment area subjected to in situ heat treatment. Migration inhibition
systems may be implemented to inhibit
contaminants from migrating to areas in the formation that are not to be
subjected to in situ heat treatment.
In some embodiments, a barrier (for example, a low temperature zone or freeze
barrier) surrounds at least a
portion of the perimeter of a treatment area. The barrier may be 20 m to 100
in from the closest heaters in the
treatment area used in the in situ heat treatment process to heat the
formation. Some contaminants may migrate
outwards toward the barrier through fractures or highly permeable zones and
condense in the formation.
In some in situ heat treatment embodiments, a migration inhibition system may
be used to minimize or
eliminate migration of formation fluid from the treatment area of the in situ
heat treatment process. FIG. 134 depicts
a representation of a fluid migration inhibition system. Barrier 922 may
surround treatment area 882. Migration
inhibition wells 924 may be placed in the formation between barrier 922 and
treatment area 882. Migration
inhibition wells 924 may be offset from wells used to heat the formation
and/or from production wells used to
produce fluid from the formation. Migration inhibition wells 924 may be placed
in formation that is below pyrolysis
and/or dissociation temperatures of minerals in the formation.
In some embodiments, one or more of the migration inhibition wells 924 include
heaters. The heaters may
be used to heat portions of the formation adjacent to the wells to a
relatively low temperature. The relatively low
temperature may be a temperature below a dissociation temperature of minerals
in the formation adjacent to the well
or below a pyrolysis temperature of hydrocarbons in the formation. The
temperature that the low temperature heater
wells raise the formation to may be less than 260 C, less than 230 C, or
less than 200 C. In some embodiments,
heating elements in low temperature wells 924 may be tailored so that the
heating elements only heat portions of the
formation that have permeability sufficient to allow for the migration of
fluid (for example, fracture systems).
Some or all migration inhibition wells 924 may be injector wells that allow
for the introduction of a sweep
fluid into the formation. The injector wells may include smart well
technology. Sweep fluid may be introduced into
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the formation through critical orifices, perforations or other types of
openings in the injector wells. In some
embodiments, the sweep fluid is carbon dioxide. The carbon dioxide may be
carbon dioxide produced from an in
situ heat treatment process. The sweep fluid may be or include other fluids,
such as nitrogen, methane or other non-
condensable hydrocarbons, exhaust gases, air, and/or steam. The sweep fluid
may provide positive pressure in the
formation outside of treatment area 882. The positive pressure may inhibit
migration of formation fluid from
treatment area 882 towards barrier 922. The sweep fluid may move through
fractures in the formation toward or into
treatment area 882. The sweep fluid may carry fluids that have migrated away
from treatment area 882 back to the
treatment area. The pressure of the fluid introduced through migration
inhibition wells 924 may be maintained
below the fracture pressure of the formation.
Alternative energy sources may be used to supply electricity for subsurface
electric heaters. Alternative
energy sources include, but are not limited to, wind, off-peak power,
hydroelectric power, geothermal, solar, and
tidal wave action. Some of these alternative energy sources provide
intermittent, time-variable power, or power-
variable power. To provide power for subsurface electric heaters, power
provided by these alternative energy
sources may be conditioned to produce power with appropriate operating
parameters (for example, voltage,
frequency, and/or current) for the subsurface heaters.
FIG. 135 illustrates a schematic of an embodiment using wind to generate
electricity for subsurface heaters.
The generated electrical power may be used to power other equipment used to
treat a subsurface formation such as,
but not limited to, pumps, computers, or other electrical equipment. In
certain embodiments, windmill 926 is used to
generate electricity to power heaters 760. Windmill 926 may represent one or
more windmills in a wind farm. The
windmills convert wind to a usable mechanical form of motion. In some
embodiments, the wind farm may include
advanced windmills as suggested by the National Renewable Energy Laboratory
(Golden, Colorado, U.S.A.). In
some embodiments, windmill 926 includes other intermittent, time-variable, or
power-variable power sources.
In some embodiments, gas turbine 928 is used to generate electricity to power
heaters 760. Windmill 926
and/or gas turbine 928 may be coupled to transformer 930. Transformer 930 may
convert power from windmill 926
and/or gas turbine 928 into electrical power with appropriate operating
parameters for heaters 760 (for example, AC
or DC power with appropriate voltage, current, and/or frequency may be
generated by the transformer).
In certain embodiments, tap controller 932 is coupled to transformer 930,
control system 934 and heaters
760. Tap controller 932 may monitor and control transformer 930 to maintain a
constant voltage to heaters 760,
regardless of the load of the heaters. Tap controller 932 may control power
output in a range from 5 MVA
(megavolt amps) to 500 MVA, from 10 MVA to 400 MVA, or from 20 MVA to 300 MVA.
As an example, during
operation, an overload of voltage may be sent from transformer 930. Tap
controller 932 may distribute the excess
load to other heaters and/or other equipment in need of power. In some
embodiments, tap controller 932 may store
the excess load for future use.
Control system 934 may control tap controller 932. Control system 934 may be,
for example, a computer
controller or an analog logic system. Control system 934 may use data supplied
from power sensors 936 to generate
predictive algorithms and/or control tap controller 932. For example, data may
be an amount of power generated
from windmill 926, gas turbine 928, and/or transformer 930. Data may also
include an amount of resistive load of
heaters 760.
Automatic voltage regulation for resistive load of a heater maintains the life
of the heaters and/or allows
constant heat output from the heaters to a subsurface formation. Adjusting the
load demands instead of adjusting the
power source allows enhanced control of power supplied to heaters and/or other
equipment that requires electricity.
Power supplied to heaters 760 may be controlled within selected limits (for
example, a power supplied and/or
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controlled to a heater within 1%, 5%, 10%, or 20% of power required by the
heater). Control of power supplied
from alternatNe energy sources may allow output of prime power at its rating,
allow energy produced (for example,
from an intermittent source, a subsurface formation, or a hydroelectric
source) to be stored and used later, and/or
allow use of power generated by intermittent power sources to be used as a
constant source of energy.
Some hydrocarbon containing formations, such as oil shale formations, may
include nahcolite, trona,
dawsonite, and/or other minerals within the formation. In some embodiments,
nahcolite is contained in partially
unleached or unleached portions of the formation. Unleached portions of the
formation are parts of the formation
where minerals have not been removed by groundwater in the formation. For
example, in the Piceance basin in
Colorado, U.S.A., unleached oil shale is found below a depth of about 500 m
below grade. Deep unleached oil shale
formations in the Piceance basin center tend to be relatively rich in
hydrocarbons. For example, about 0.10 liters to
about 0.15 liters of oil per kilogram (L/kg) of oil shale may be producible
from an unleached oil shale formation.
Nahcolite is a mineral that includes sodium bicarbonate (NaHCO3). Nahcolite
may be found in formations
in the Green River lakebeds in Colorado, U.S.A. In some embodiments, at least
about 5 weight %, at least about 10
weight %, or at least about 20 weight % nahcolite may be present in the
formation. Dawsonite is a mineral that
includes sodium aluminum carbonate (NaAl(CO3)(OH)2). Dawsonite is typically
present in the formation at weight
percents greater than about 2 weight % or, in some embodiments, greater than
about 5 weight %. Nahcolite and/or
dawsonite may dissociate at temperatures used in an in situ heat treatment
process. The dissociation is strongly
endothermic and may produce large amounts of carbon dioxide.
Nahcolite and/or dawsonite may be solution mined prior to, during, and/or
following treatment of the
formation in situ to avoid dissociation reactions and/or to obtain desired
chemical compounds. In certain
embodiments, hot water or steam is used to dissolve nahcolite in situ to form
an aqueous sodium bicarbonate
solution before the in situ heat treatment process is used to process
hydrocarbons in the formation. Nahcolite may
form sodium ions (Nat) and bicarbonate ions (HCO3-) in aqueous solution. The
solution may be produced from the
formation through production wells, thus avoiding dissociation reactions
during the in situ heat treatment process. In
some embodiments, dawsonite is thermally decomposed to alumina during the in
situ heat treatment process for
treating hydrocarbons in the formation. The alumina is solution mined after
completion of the in situ heat treatment
process.
Production wells and/or injection wells used for solution mining and/or for in
situ heat treatment processes
may include smart well technology. The smart well technology allows the first
fluid to be introduced at a desired
zone in the formation. The smart well technology allows the second fluid to be
removed from a desired zone of the
formation.
Formations that include nahcolite and/or dawsonite may be treated using the in
situ heat treatment process.
A perimeter barrier may be formed around the portion of the formation to be
treated. The perimeter barrier may
inhibit migration of water into the treatment area. During solution mining
and/or the in situ heat treatment process,
the perimeter barrier may inhibit migration of dissolved minerals and
formation fluid from the treatment area.
During initial heating, a portion of the formation to be treated may be raised
to a temperature below the dissociation
temperature of the nahcolite. The temperature may be at most about 90 C, or
in some embodiments, at most about
80 C. The temperature may be any temperature that increases the solvation
rate of nahcolite in water, but is also
below a temperature at which nahcolite dissociates (above about 95 C at
atmospheric pressure).
A first fluid may be injected into the heated portion. The first fluid may
include water, brine, steam, or
other fluids that form a solution with nahcolite and/or dawsonite. The first
fluid may be at an increased temperature,
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for example, about 90 C, about 95 C, or about 100 C. The increased
temperature may be similar to the
temperature of the portion of the formation.
In some embodiments, the first fluid is injected at an increased temperature
into a portion of the formation
that has not been heated by heat sources. The increased temperature may be a
temperature below a boiling point of
the first fluid, for example, about 90 C for water. Providing the first fluid
at an increased temperature increases a
temperature of a portion of the formation. In certain embodiments, additional
heat may be provided from one or
more heat sources in the formation during and/or after injection of the first
fluid.
In other embodiments, the first fluid is or includes steam. The steam may be
produced by forming steam in
a previously heated portion of the formation (for example, by passing water
through u-shaped wellbores that have
been used to heat the formation), by heat exchange with fluids produced from
the formation, and/or by generating
steam in standard steam production facilities. In some embodiments, the first
fluid may be fluid introduced directly
into a hot portion of the portion and produced from the hot portion of the
formation. The first fluid may then be used
as the first fluid for solution mining.
In some embodiments, heat from a hot previously treated portion of the
formation is used to heat water,
brine, and/or steam used for solution mining a new portion of the formation.
Heat transfer fluid may be introduced
into the hot previously treated portion of the formation. The heat transfer
fluid may be water, steam, carbon dioxide,
and/or other fluids. Heat may transfer from the hot formation to the heat
transfer fluid. The heat transfer fluid is
produced from the formation through production wells. The heat transfer fluid
is sent to a heat exchanger. The heat
exChanger may heat water, brine, and/or steam used as the first fluid to
solution mine the new portion of the
formation. The heat transfer fluid may be reintroduced into the heated portion
of the formation to produce additional
hot heat transfer fluid. In some embodiments, heat transfer fluid produced
from the formation is treated to remove
hydrocarbons or other materials before being reintroduced into the formation
as part of a remediation process for the
heated portion of the formation.
Steam injected for solution mining may have a temperature below the pyrolysis
temperature of
hydrocarbons in the formation. Injected steam may be at a temperature below
250 C, below 300 C, or below 400
C. The injected steam may be at a temperature of at least 150 C, at least 135
C, or at least 125 C. Injecting
steam at pyrolysis temperatures may cause problems as hydrocarbons pyrolyze
and hydrocarbon fines mix with the
steam. The mixture of fines and steam may reduce permeability and/or cause
plugging of production wells and the
formation. Thus, the injected steam temperature is selected to inhibit
plugging of the formation and/or wells in the
formation.
The temperature of the first fluid may be varied during the solution mining
process. As the solution mining
progresses and the nahcolite being solution mined is farther away from the
injection point, the first fluid temperature
may be increased so that steam and/or water that reaches the nahcolite to be
solution mined is at an elevated
temperature below the dissociation temperature of the nahcolite. The steam
and/or water that reaches the nahcolite is
also at a temperature below a temperature that promotes plugging of the
formation and/or wells in the formation (for
example, the pyrolysis temperature of hydrocarbons in the formation).
A second fluid may be produced from the formation following injection of the
first fluid into the formation.
The second fluid may include material dissolved in the first fluid. For
example, the second fluid may include
carbonic acid or other hydrated carbonate compounds formed from the
dissolution of nahcolite in the first fluid. The
second fluid may also include minerals and/or metals. The minerals and/or
metals may include sodium, aluminum,
phosphorus, and other elements.
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Solution mining the formation before the in situ heat treatment process allows
initial heating of the
formation to be provided by heat transfer from the first fluid used during
solution mining. Solution mining nahcolite
or other minerals that decompose or dissociate by means of endothermic
reactions before the in situ heat treatment
process avoids having energy supplied to heat the formation being used to
support these endothermic reactions.
Solution mining allows for production of minerals with commercial value.
Removing nahcolite or other minerals
before the in situ heat treatment process removes mass from the formation.
Thus, less mass is present in the
formation that needs to be heated to higher temperatures and heating the
formation to higher temperatures may be
achieved more quickly and/or more efficiently. Removing mass from the
formation also may increase the
permeability of the formation. Increasing the permeability may reduce the
number of production wells needed for
the in situ heat treatment process. In certain embodiments, solution mining
before the in situ heat treatment process
reduces the time delay between startup of heating of the formation and
production of hydrocarbons by two years or
more.
FIG. 136 depicts an embodiment of solution mining well 938. Solution mining
well 938 may include
insulated portion 940, input 942, packer 944, and return 946. Insulated
portion 940 may be adjacent to overburden
458 of the formation. In some embodiments, insulated portion 940 is low
conductivity cement. The cement may be
low density, low conductivity vermiculite cement or foam cement. Input 942 may
direct the first fluid to treatment
area 882. Perforations or other types of openings in input 942 allow the first
fluid to contact formation material in
treatment area 882. Packer 944 may be a bottom seal for input 942. First fluid
passes through input 942 into the
formation. First fluid dissolves minerals and becomes second fluid. The second
fluid may be denser than the first
fluid. An entrance into return 946 is typically located below the perforations
or openings that allow the first fluid to
enter the formation. Second fluid flows to return 946. The second fluid is
removed from the formation through
return 946.
FIG. 137 depicts a representation of an embodiment of solution mining well
938. Solution mining well 938
may include input 942 and return 946 in casing 948. Inlet 942 and/or return
946 may be coiled tubing.
FIG. 138 depicts a representation of an embodiment of solution mining well
938. Insulating portions 940
may surround return 946. Input 942 may be positioned in return 946. In some
embodiments, input 942 may
introduce the first fluid into the treatment area below the entry point into
return 946. In some embodiments,
crossovers may be used to direct first fluid flow and second fluid flow so
that first fluid is introduced into the
formation from input 942 above the entry point of second fluid into return
946.
FIG. 139 depicts an elevational view of an embodiment of wells used for
solution mining and/or for an in
situ heat treatment process. Solution mining wells 938 may be placed in the
formation in an equilateral triangle
pattern. In some embodiments, the spacing between solution mining wells 938
may be about 36 m. Other spacings
may be used. Heat sources 202 may also be placed in an equilateral triangle
pattern. Solution mining wells 938
substitute for certain heat sources of the pattern. In the shown embodiment,
the spacing between heat sources 202 is
about 9 m. The ratio of solution mining well spacing to heat source spacing is
4. Other ratios may be used if
desired. After solution mining is complete, solution mining wells 938 may be
used as production wells for the in situ
heat treatment process.
In some formations, a portion of the formation with unleached minerals may be
below a leached portion of
the formation. The unleached portion may be thick and substantially
impermeable. A treatment area may be formed
in the unleached portion. Unleached portion of the formation to the sides,
above and/or below the treatment area
may be used as barriers to fluid flow into and out of the treatment area. A
first treatment area may be solution mined
to remove minerals, increase permeability in the treatment area, and/or
increase the richness of the hydrocarbons in
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the treatment area. After solution mining the first treatment area, in situ
heat treatment may be used to treat a second
treatment area. In some embodiments, the second treatment area is the same as
the first treatment area. In some
embodiments, the second treatment has a smaller volume than the first
treatment area so that heat provided by
outermost heat sources to the formation do not raise the temperature of
unleached portions of the formation to the
dissociation temperature of the minerals in the unleached portions.
In some embodiments, a leached or partially leached portion of the formation
above an unleached portion of
the formation may include significant amounts of hydrocarbon materials. An in
situ heating process may be used to
produce hydrocarbon fluids from the unleached portions and the leached or
partially leached portions of the
formation. FIG. 140 depicts a representation of a formation with unleached
zone 950 below leached zone 952.
Unleached zone 950 may have an initial permeability before solution mining of
less than 0.1 millidarcy. Solution
mining wells 938 may be placed in the formation. Solution mining wells 938 may
include smart well technology
that allows the position of first fluid entrance into the formation and second
flow entrance into the solution mining
wells to be changed. Solution mining wells 938 may be used to form first
treatment area 882' in unleached zone
950. Unleached zone 950 may initially be substantially impermeable. Unleached
portions of the formation may
form a top barrier and side barriers around first treatment area 882'. After
solution mining first treatment area 882',
the portions of solution mining wells 938 adjacent to the first treatment area
may be converted to production wells
and/or heater wells.
Heat sources 202 in first treatment area 882' may be used to heat the first
treatment area to pyrolysis
temperatures. In some embodiments, one or more heat sources 202 are placed in
the formation before first treatment
area 882' is solution mined. The heat sources may be used to provide initial
heating to the formation to raise the
temperature of the formation and/or to test the functionality of the heat
sources. In some embodiments, one or more
heat sources are installed during solution mining of the first treatment area,
or after solution mining is completed.
After solution mining, heat sources 202 may be used to raise the temperature
of at least a portion of first treatment
area 882' above the pyrolysis and/or mobilization temperature of hydrocarbons
in the formation to result in the
generation of mobile hydrocarbons in the first treatment area.
Barrier wells 200 may be introduced into the formation. Ends of barrier wells
200 may extend into and
terminate in unleached zone 950. Unleached zone 950 may be impermeable. In
some embodiments, barrier wells
200 are freeze wells. Barrier wells 200 may be used to form a barrier to fluid
flow into or out of unleached zone
952. Barrier wells 200, overburden 458, and the unleached material above first
treatment area 882' may define
second treatment area 882". In some embodiments, a first fluid may be
introduced into second treatment area 882"
through solution mining wells 938 to raise the initial temperature of the
formation in second treatment area 882" and
remove any residual soluble minerals from the second treatment area. In some
embodiments, the top barrier above
first treatment area 882' may be solution mined to remove minerals and combine
first treatment area 882' and
second treatment area 882" into one treatment area. After solution mining,
heat sources may be activated to heat the
treatment area to pyrolysis temperatures.
FIG. 141 depicts an embodiment for solution mining the formation. Barrier 922
(for example, a frozen
barrier and/or a grout barrier) may be formed around a perimeter of treatment
area 882 of the formation. The
footprint defined by the barrier may have any desired shape such as circular,
square, rectangular, polygonal, or
irregular shape. Barrier 922 may be any barrier formed to inhibit the flow of
fluid into or out of treatment area 882.
For example, barrier 922 may include one or more freeze wells that inhibit
water flow through the barrier. Barrier
922 may be formed using one or more barrier wells 200. Formation of barrier
922 may be monitored using monitor
wells 956 and/or by monitoring devices placed in barrier wells 200.
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Water inside treatment area 882 may be pumped out of the treatment area
through injection wells 748
and/or production wells 206. In certain embodiments, injection wells 748 are
used as production wells 206 and vice
versa (the wells are used as both injection wells and production wells). Water
may be pumped out until a production
rate of water is low or stops.
Heat may be provided to treatment area 882 from heat sources 202. Heat sources
may be operated at
temperatures that do not result in the pyrolysis of hydrocarbons in the
formation adjacent to the heat sources. In
some embodiments, treatment area 882 is heated to a temperature from about 90
C to about 120 C (for example, a
temperature of about 90 C, 95 C, 100 C, 110 C, or 120 C). In certain
embodiments, heat is provided to
treatment area 882 from the first fluid injected into the formation. The first
fluid may be injected at a temperature
from about 90 C to about 120 C (for example, a temperature of about 90 C,
95 C, 100 C, 110 C, or 120 C). In
some embodiments, heat sources 202 are installed in treatment area 882 after
the treatment area is solution mined.
In some embodiments, some heat is provided from heaters placed in injection
wells 748 and/or production wells 206.
A temperature of treatment area 882 may be monitored using temperature
measurement devices placed in monitoring
wells 956 and/or temperature measurement devices in injection wells 748,
production wells 206, and/or heat sources
202.
The first fluid is injected through one or more injection wells 748. In some
embodiments, the first fluid is
hot water. The first fluid may mix and/or combine with non-hydrocarbon
material that is soluble in the first fluid,
such as nahcolite, to produce a second fluid. The second fluid may be removed
from the treatment area through
injection wells 748, production wells 206, and/or heat sources 202. Injection
wells 748, production wells 206, and/or
heat sources 202 may be heated during removal of the second fluid. Heating one
or more wells during removal of
the second fluid may maintain the temperature of the fluid during removal of
the fluid from the treatment area above
a desired value. After producing a desired amount of the soluble non-
hydrocarbon material from treatment area 882,
solution remaining within the treatment area may be removed from the treatment
area through injection wells 748,
production wells 206, and/or heat sources 202. The desired amount of the
soluble non-hydrocarbon material may be
less than half of the soluble non-hydrocarbon material, a majority of the
soluble non-hydrocarbon material,
substantially all of the soluble non-hydrocarbon material, or all of the
soluble non-hydrocarbon material. Removing
soluble non-hydrocarbon material may produce a relatively high permeability
treatment area 882.
Hydrocarbons within treatment area 882 may be pyrolyzed and/or produced using
the in situ heat treatment
process following removal of soluble non-hydrocarbon materials. The relatively
high permeability treatment area
allows for easy movement of hydrocarbon fluids in the formation during in situ
heat treatment processing. The
relatively high permeability treatment area provides an enhanced collection
area for pyrolyzed and mobilized fluids
in the formation. During the in situ heat treatment process, heat may be
provided to treatment area 882 from heat
sources 202. A mixture of hydrocarbons may be produced from the formation
through production wells 206 and/or
heat sources 202. In certain embodiments, injection wells 748 are used as
either production wells and/or heater wells
during the in situ heat treatment process.
In some embodiments, a controlled amount of oxidant (for example, air and/or
oxygen) is provided to
treatment area 882 at or near heat sources 202 when a temperature in the
formation is above a temperature sufficient
to support oxidation of hydrocarbons. At such a temperature, the oxidant
reacts with the hydrocarbons to provide
heat in addition to heat provided by electrical heaters in heat sources 202.
The controlled amount of oxidant may
facilitate oxidation of hydrocarbons in the formation to provide additional
heat for pyrolyzing hydrocarbons in the
formation. The oxidant may more easily flow through treatment area 882 because
of the increased permeability of
the treatment area after removal of the non-hydrocarbon materials. The oxidant
may be provided in a controlled
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manner to control the heating of the formation. The amount of oxidant provided
is controlled so that uncontrolled
heating of the formation is avoided. Excess oxidant and combustion products
may flow to production wells in
treatment area 882.
Following the in situ heat treatment process, treatment area 882 may be cooled
by introducing water to
produce steam from the hot portion of the formation. Introduction of water to
produce steam may vaporize some
hydrocarbons remaining in the formation. Water may be injected through
injection wells 748. The injected water
may cool the formation. The remaining hydrocarbons and generated steam may be
produced through production
wells 206 and/or heat sources 202. Treatment area 882 may be cooled to a
temperature near the boiling point of
water. The steam produced from the formation may be used to heat a first fluid
used to solution mine another
portion of the formation.
Treatment area 882 may be further cooled to a temperature at which water will
condense in the formation.
Water and/or solvent may be introduced into and be removed from the treatment
area. Removing the condensed
water and/or solvent from treatment area 882 may remove any additional soluble
material remaining in the treatment
area. The water and/or solvent may entrain non-soluble fluid present in the
formation. Fluid may be pumped out of
treatment area 882 through production well 206 and/or heat sources 202. The
injection and removal of water and/or
solvent may be repeated until a desired water quality within treatment area
882 is achieved. Water quality may be
measured at injection wells 748, heat sources 202, and/or production wells
206. The water quality may substantially
match or exceed the water quality of treatment area 882 prior to treatment.
In some embodiments, treatment area 882 may include a leached zone located
above an unleached zone.
The leached zone may have been leached naturally and/or by a separate leaching
process. In certain embodiments,
the unleached zone may be at a depth of at least about 500 m. A thickness of
the unleached zone may be between
about 100 m and about 500 m. However, the depth and thickness of the unleached
zone may vary depending on, for
example, a location of treatment area 882 and/or the type of formation. In
certain embodiments, the first fluid is
injected into the unleached zone below the leached zone. Heat may also be
provided into the unleached zone.
In certain embodiments, a section of a formation may be left untreated by
solution mining and/or unleached.
The unleached section may be proximate a selected section of the formation
that has been leached and/or solution
mined by providing the first fluid as described above. The unleached section
may inhibit the flow of water into the
selected section. In some embodiments, more than one unleached section may be
proximate a selected section.
Nahcolite may be present in the formation in layers or beds. Prior to solution
mining, such layers may have
little or no permeability. In certain embodiments, solution mining layered or
bedded nahcolite from the formation
causes vertical shifting in the formation. FIG. 142 depicts an embodiment of a
formation with nahcolite layers in the
formation below overburden 458 and before solution mining nahcolite from the
formation. Hydrocarbon layers
460A have substantially no nahcolite and hydrocarbon layers 460B have
nahcolite. FIG. 143 depicts the formation
of FIG. 142 after the nahcolite has been solution mined. Layers 460B have
collapsed due to the removal of the
nahcolite from the layers. The collapsing of layers 460B causes compaction of
the layers and vertical shifting of the
formation. The hydrocarbon richness of layers 460B is increased after
compaction of the layers. In addition, the
permeability of layers 460B may remain relatively high after compaction due to
removal of the nahcolite. The
permeability may be more than 5 darcy, more than 1 darcy, or more than 0.5
darcy after vertical shifting. The
permeability may provide fluid flow paths to production wells when the
formation is treated using an in situ heat
treatment process. The increased permeability may allow for a large spacing
between production wells. Distances
between production wells for the in situ heat treatment system after solution
mining may be greater than 10 m,
greater than 20 m, or greater than 30 meters. Heater wells may be placed in
the formation after removal of nahcolite
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and the subsequent vertical shifting. Forming heater wellbores and/or
installing heaters in the formation after the
vertical shifting protects the heaters from being damaged due to the vertical
shifting.
In certain embodiments, removing nahcolite from the formation interconnects
two or more wells in the
formation. Removing nahcolite from zones in the formation may increase the
permeability in the zones. Some
zones may have more nahcolite than others and become more permeable as the
nahcolite is removed. At a certain
time, zones with the increased permeability may interconnect two or more wells
(for example, injection wells or
production wells) in the formation.
FIG. 144 depicts an embodiment of two injection wells interconnected by a zone
that has been solution
mined to remove nahcolite from the zone. Solution mining wells 938 are used to
solution mine hydrocarbon layer
460, which contains nahcolite. During the initial portion of the solution
mining process, solution mining wells 938
are used to inject water and/or other fluids, and to produce dissolved
nahcolite fluids from the formation. Each
solution mining well 938 is used to inject water and produce fluid from a near
wellbore region as the permeability of
hydrocarbon layer is not sufficient to allow fluid to flow between the
injection wells. In certain embodiments, zone
958 has more nahcolite than other portions of hydrocarbon layer 460. With
increased nahcolite removal from zone
958, the permeability of the zone may increase. The permeability increases
from the wellbores outwards as
nahcolite is removed from zone 958. At some point during solution mining of
the formation, the permeability of
zone 958 increases to allow solution mining wells 938 to become interconnected
such that fluid will flow between
the wells. At this time, one solution mining well 938' may be used to inject
water while the other solution mining
well 938" is used to produce fluids from the formation in a continuous
process. Injecting in one well and producing
from a second well may be more economical and more efficient in removing
nahcolite, as compared to injecting and
producing through the same well. In some embodiments, additional wells may be
drilled into zone 958 and/or
hydrocarbon layer 460 in addition to injection wells 748. The additional wells
may be used to circulate additional
water and/or to produce fluids from the formation. The wells may later be used
as heater wells and/or production
wells for the in situ heat treatment process treatment of hydrocarbon layer
460.
In some embodiments, the second fluid produced from the formation during
solution mining is used to
produce sodium bicarbonate. Sodium bicarbonate may be used in the food and
pharmaceutical industries, in leather
tanning, in fire retardation, in wastewater treatment, and in flue gas
treatment (flue gas desulphurization and
hydrogen chloride reduction). The second fluid may be kept pressurized and at
an elevated temperature when
removed from the formation. The second fluid may be cooled in a crystallizer
to precipitate sodium bicarbonate.
In some embodiments, the second fluid produced from the formation during
solution mining is used to
produce sodium carbonate, which is also referred to as soda ash. Sodium
carbonate may be used in the manufacture
of glass, in the manufacture of detergents, in water purification, polymer
production, tanning, paper manufacturing,
effluent neutralization, metal refining, sugar extraction, and/or cement
manufacturing. The second fluid removed
from the formation may be heated in a treatment facility to form sodium
carbonate (soda ash) and/or sodium
carbonate brine. Heating sodium bicarbonate will form sodium carbonate
according to the equation:
(7) 2NaHCO3 Na2CO3 + CO2 + H20.
In certain embodiments, the heat for heating the sodium bicarbonate is
provided using heat from the
formation. For example, a heat exchanger that uses steam produced from the
water introduced into the hot formation
may be used to heat the second fluid to dissociation temperatures of the
sodium bicarbonate. In some embodiments,
the second fluid is circulated through the formation to utilize heat in the
formation for further reaction. Steam and/or
hot water may also be added to facilitate circulation. The second fluid may be
circulated through a heated portion of
the formation that has been subjected to the in situ heat treatment process to
produce hydrocarbons from the
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formation. At least a portion of the carbon dioxide generated during sodium
carbonate dissociation may be adsorbed
on carbon that remains in the formation after the in situ heat treatment
process. In some embodiments, the second
fluid is circulated through conduits previously used to heat the formation.
In some embodiments, higher temperatures are used in the formation (for
example, above about 120 C,
above about 130 C, above about 150 C, or below about 250 C) during solution
mining of nahcolite. The first
fluid is introduced into the forniation under pressure sufficient to inhibit
sodium bicarbonate from dissociating to
produce carbon dioxide. The pressure in the formation may be maintained at
sufficiently high pressures to inhibit
such nahcolite dissociation but below pressures that would result in
fracturing the formation. In addition, the
pressure in the formation may be maintained high enough to inhibit steam
formation if hot water is being introduced
in the formation. In some embodiments, a portion of the nahcolite may begin to
decompose in situ. In such cases,
nahcolite is removed from the formation as soda ash. If soda ash is produced
from solution mining of nahcolite, the
soda ash may be transported to a separate facility for treatment. The soda ash
may be transported through a pipeline
to the separate facility.
As described above, in certain embodiments, following removal of nahcolite
from the formation, the
formation is treated using the in situ heat treatment process to produce
formation fluids from the formation. If
dawsonite is present in the formation, dawsonite within the heated portion of
the formation decomposes during
heating of the formation to pyrolysis temperature. Dawsonite typically
decomposes at temperatures above 270 C
according to the reaction:
(8) 2NaAl(OH)2CO3 ---> Na2CO3 + A1203 + 2H20 + CO2.
Sodium carbonate may be removed from the formation by solution mining the
formation with water or
other fluid into which sodium carbonate is soluble. In certain embodiments,
alumina formed by dawsonite
decomposition is solution mined using a chelating agent. The chelating agent
may be injected through injection
wells, production wells, and/or heater wells used for solution mining
nahcolite and/or the in situ heat treatment
process (for example, injection wells 748, production wells 206, and/or heat
sources 202 depicted in FIG. 141). The
chelating agent may be an aqueous acid. In certain embodiments, the chelating
agent is EDTA
(ethylenediaminetetraacetic acid). Other examples of possible chelating agents
include, but are not limited to,
ethylenediamine, porphyrins, dimercaprol, nitrilotriacetic acid,
diethylenetriaminepentaacetic acid, phosphoric acids,
acetic acid, acetoxy benzoic acids, nicotinic acid, pyruvic acid, citric acid,
tartaric acid, malonic acid, imidizole,
ascorbic acid, phenols, hydroxy ketones, sebacic acid, and boric acid. The
mixture of chelating agent and alumina
may be produced through production wells or other wells used for solution
mining and/or the in situ heat treatment
process (for example, injection wells 748, production wells 206, and/or heat
sources 202, which are depicted in FIG.
141). The alumina may be separated from the chelating agent in a treatment
facility. The recovered chelating agent
may be recirculated back to the formation to solution mine more alumina.
In some embodiments, alumina within the formation may be solution mined using
a basic fluid after the in
situ heat treatment process. Basic fluids include, but are not limited to,
sodium hydroxide, ammonia, magnesium
hydroxide, magnesium carbonate, sodium carbonate, potassium carbonate,
pyridine, and amines. In an embodiment,
sodium carbonate brine, such as 0.5 Normal Na2CO3, is used to solution mine
alumina. Sodium carbonate brine may
be obtained from solution mining nahcolite from the formation. Obtaining the
basic fluid by solution mining the
nahcolite may significantly reduce costs associated with obtaining the basic
fluid. The basic fluid may be injected
into the formation through a heater well and/or an injection well. The basic
fluid may combine with alumina to form
an alumina solution that is removed from the formation. The alumina solution
may be removed through a heater
well, injection well, or production well.
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Alumina may be extracted from the alumina solution in a treatment facility. In
an embodiment, carbon
dioxide is bubbled through the alumina solution to precipitate the alumina
from the basic fluid. Carbon dioxide may
be obtained from dissociation of nahcolite, from the in situ heat treatment
process, or from decomposition of the
dawsonite during the in situ heat treatment process.
In certain embodiments, a formation may include portions that are
significantly rich in either nahcolite or
dawsonite only. For example, a formation may contain significant amounts of
nahcolite (for example, at least about
20 weight %, at least about 30 weight %, or at least about 40 weight %) in a
depocenter of the formation. The
depocenter may contain only about 5 weight % or less dawsonite on average.
However, in bottom layers of the
formation, a weight percent of dawsonite may be about 10 weight % or even as
high as about 25 weight %. In such
formations, it may be advantageous to solution mine for nahcolite only in
nahcolite-rich areas, such as the
depocenter, and solution mine for dawsonite only in the dawsonite-rich areas,
such as the bottom layers. This
selective solution mining may significantly reduce fluid costs, heating costs,
and/or equipment costs associated with
operating the solution mining process.
In certain formations, dawsonite composition varies between layers in the
formation. For example, some
layers of the formation may have dawsonite and some layers may not. In certain
embodiments, more heat is
provided to layers with more dawsonite than to layers with less dawsonite.
Tailoring heat input to provide more heat
to certain dawsonite layers more uniformly heats the formation as the reaction
to decompose dawsonite absorbs
some of the heat intended for pyrolyzing hydrocarbons. FIG. 145 depicts an
embodiment for heating a formation
with dawsonite in the formation. Hydrocarbon layer 460 may be cored to assess
the dawsonite composition of the
hydrocarbon layer. The mineral composition may be assessed using, for example,
FTIR (Fourier transform infrared
spectroscopy) or x-ray diffraction. Assessing the core composition may also
assess the nahcolite composition of the
core. After assessing the dawsonite composition, heater 716 may be placed in
wellbore 452. Heater 716 includes
sections to provide more heat to hydrocarbon layers with more dawsonite in the
layers (hydrocarbon layers 460D).
Hydrocarbon layers with less dawsonite (hydrocarbon layers 460C) are provided
with less heat by heater 716. Heat
output of heater 716 may be tailored by, for example, adjusting the resistance
of the heater along the length of the
heater. In one embodiment, heater 716 is a temperature limited heater,
described herein, that has a higher
temperature limit (for example, higher Curie temperature) in sections
proximate layers 460D as compared to the
temperature limit (Curie temperature) of sections proximate layers 460C. The
resistance of heater 716 may also be
adjusted by altering the resistive conducting materials along the length of
the heater to supply a higher energy input
(watts per meter) adjacent to dawsonite rich layers.
Solution mining dawsonite and nahcolite may be relatively simple processes
that produce alumina and soda
ash from the formation. In some embodiments, hydrocarbons produced from the
formation using the in situ heat
treatment process may be fuel for a power plant that produces direct current
(DC) electricity at or near the site of the
in situ heat treatment process. The produced DC electricity may be used on the
site to produce aluminum metal from
the alumina using the Hall process. Aluminum metal may be produced from the
alumina by melting the alumina in a
treatment facility on the site. Generating the DC electricity at the site may
save on costs associated with using
hydrotreaters, pipelines, or other treatment facilities associated with
transporting and/or treating hydrocarbons
produced from the formation using the in situ heat treatment process.
In some embodiments, acid may be introduced into the formation through
selected wells to increase the
porosity adjacent to the wells. For example, acid may be injected if the
formation comprises limestone or dolomite.
The acid used to treat the selected wells may be acid produced during in situ
heat treatment of a section of the
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formation (for example, hydrochloric acid), or acid produced from byproducts
of the in situ heat treatment process
(for example, sulfuric acid produced from hydrogen sulfide or sulfur).
In some embodiments, a perimeter barrier may be formed around the portion of
the formation to be treated.
The perimeter barrier may inhibit migration of formation fluid into or out of
the treatment area. The perimeter
barrier may be a frozen barrier and/or a grout barrier. After formation of the
perimeter barrier, the treatment area
may be processed to produce desired products.
Formations that include non-hydrocarbon materials may be treated to remove
and/or dissolve a portion of
the non-hydrocarbon materials from a section of the formation before
hydrocarbons are produced from the section.
In some embodiments, the non-hydrocarbon materials are removed by solution
mining. Removing a portion of the
non-hydrocarbon materials may reduce the carbon dioxide generation sources
present in the formation. Removing a
portion of the non-hydrocarbon materials may increase the porosity and/or
permeability of the section of the
formation. Removing a portion of the non-hydrocarbon materials may result in a
raised temperature in the section of
the formation.
After solution mining, some of the wells in the treatment may be converted to
heater wells, injection wells,
and/or production wells. In some embodiments, additional wells are formed in
the treatment area. The wells may be
heater wells, injection wells, and/or production wells. Logging techniques may
be employed to assess the physical
characteristics, including any vertical shifting resulting from the solution
mining, and/or the composition of material
in the formation. Packing, baffles or other techniques may be used to inhibit
formation fluid from entering the heater
wells. The heater wells may be activated to heat the formation to a
temperature sufficient to support combustion.
One or more production wells may be positioned in permeable sections of the
treatment area. Production
wells may be horizontally and/or vertically oriented. For example, production
wells may be positioned in areas of
the formation that have a permeability of greater than 5 darcy or 10 darcy. In
some embodiments, production wells
may be positioned near a perimeter barrier. A production well may allow water
and production fluids to be removed
from the formation. Positioning the production well near a perimeter barrier
enhances the flow of fluids from the
warmer zones of the formation to the cooler zones.
FIG. 146 depicts an embodiment of a process for treating a hydrocarbon
containing formation with a
combustion front. Barrier 922 (for example, a frozen barrier or a grout
barrier) may be formed around a perimeter of
treatment area 882 of the formation. The footprint defined by the barrier may
have any desired shape such as
circular, square, rectangular, polygonal, or irregular shape. Barrier 922 may
be formed using one or more barrier
wells 200. The barrier may be any barrier formed to inhibit the flow of fluid
into or out of treatment area 882. In
some embodiments, barrier 922 may be a double barrier.
Heat may be provided to treatment area 882 through heaters positioned in
injection wells 748. In some
embodiments, the heaters in injection wells 748 heat formation adjacent to the
injections wells to temperatures
sufficient to support combustion. Heaters in injection wells 748 may raise the
formation near the injection wells to
temperatures from about 90 C to about 120 C or higher (for example, a
temperature of about 90 C, 95 C, 100
C, 110 C, or 120 C).
Injection wells 748 may be used to introduce a combustion fuel, an oxidant,
steam and/or a heat transfer
fluid into treatment area 882, either before, during, or after heat is
provided to the treatment area 882 from heaters.
In some embodiments, injection wells 748 are in communication with each other
to allow the introduced fluid to
flow from one well to another. Injection wells 748 may be located at positions
that are relatively far away from
perimeter barrier 922. Introduced fluid may cause combustion of hydrocarbons
in treatment area 882. Heat from the
combustion may heat treatment area 882 and mobilize fluids toward production
wells 206.
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A temperature of treatment area 882 may be monitored using temperature
measurement devices placed in
monitoring wells and/or temperature measurement devices in injection wells
748, production wells 206, and/or
heater wells.
In some embodiments, a controlled amount of oxidant (for example, air and/or
oxygen) is provided in
injection wells 748 to advance a heat front towards production wells 206. In
some embodiments, the controlled
amount of oxidant is introduced into the formation after solution mining has
established permeable interconnectivity
between at least two injection wells. The amount of oxidant is controlled to
limit the advancement rate of the heat
front and to limit the temperature of the heat front. The advancing heat front
may pyrolyze hydrocarbons. The high
permeability in the formation allows the pyrolyzed hydrocarbons to spread in
the formation towards production
wells without being overtaken by the advancing heat front.
Vaporized formation fluid and/or gas formed during the combustion process may
be removed through gas
wells 960 and/or injection well 748. Venting of gases through the gas wells
and/or the injection well may force the
combustion front in a desired direction.
In some embodiments, the formation may be heated to a temperature sufficient
temperature to cause
pyrolysis of the formation fluid by the steam and/or heat transfer fluid. The
steam and/or heat transfer fluid may be
heated to temperatures of about 300 C, about 400 C, about 500 C, or about
600 C. In certain embodiments, the
steam and/or heat transfer fluid may be co-injected with the fuel and/or
oxidant.
FIG. 147 depicts a representation of a cross-sectional view of an embodiment
for treating a hydrocarbon
containing formation with a combustion front. As the combustion front is
initiated and/or fueled through injection
wells 748, formation fluid near periphery 962 of the combustion front becomes
mobile and flow towards production
wells 206 located proximate barrier 922. Injection wells may include smart
well technology. Combustion products
and noncondensable formation fluid may be removed from the formation through
gas wells 960. In some
embodiments, no gas wells are formed in the formation. In such embodiments,
formation fluid, combustion products
and noncondensable formation fluid are produced through production wells 206.
In embodiments that include gas
wells 960, condensable formation fluid may be produced through production well
206. In some embodiments,
production well 206 is located below injection well 748. Production well 206
may be about, or above 1 m, 5 m, to
10 m or more below injection well 748. Production well may be a horizontal
well. Periphery 962 of the combustion
front may advance from the toe of production well 206 towards the heel of the
production well. Production well 206
may include a perforated liner that allows hydrocarbons to flow into the
production well. In some embodiments, a
catalyst may be placed in production well 206. The catalyst may upgrade and/or
stabilize formation fluid in the
production well.
Carbon dioxide and/or hydrogen sulfide may be produced during in situ heat
treatment processes and during
many conventional production processes. Removal of hydrogen sulfide from
produced formation fluid may reduce
the toxicity and/or strong odor in the produced formation fluid, thus making
the formation fluid more acceptable for
transportation and/or processing. Removing carbon dioxide and/or hydrogen
sulfide from produced formation fluids
may reduce capital costs associated with removing the fluids and reduce or
eliminate the need for certain surface
facilities (for example, a Claus plant or Scot gas treater). Since carbon
dioxide has a low heating value, removal of
carbon dioxide from formation fluids may increase the heat capacity of a gas
stream separated from the formation
fluid.
Net release of carbon dioxide to the atmosphere and/or hydrogen sulfide
conversion to sulfur from an in situ
heat treatment process for hydrocarbons may be reduced by utilizing the
produced carbon dioxide and/or by storing
carbon dioxide and/or hydrogen sulfide within the formation or within another
formation. Carbon dioxide and/or
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hydrogen sulfide may be introduced into a portion of the formation below
treatment areas subjected to in situ heat
treatment processes. In some embodiments, the carbon dioxide and/or hydrogen
sulfide may be transported to
another formation.
In certain embodiments, carbon dioxide and/or hydrogen sulfide may be stored
in spent portions of
formations that have previously been subjected to in situ heat treatment
processes or other hydrocarbon recovery
processes. Carbon dioxide may absorb on or into remaining carbon containing
material in such formations.
In certain embodiments, carbon dioxide and/or hydrogen sulfide is stored in a
porous, deep saline aquifer.
The carbon dioxide and/or hydrogen sulfide may promote mineralization within
the aquifer. For example, the
introduction of carbon dioxide and hydrogen sulfide into a saline aquifer may
result in the production of carbonates
in the aquifer. In certain embodiments, carbon dioxide is stored at a depth in
the formation such that the carbon
dioxide is introduced in the formation in a supercritical state. Supercritical
carbon dioxide injection may maximize
the density of the fluid introduced into the formation. The depths of outlets
of insertion wells used to introduce
carbon dioxide and/or hydrogen sulfide in the formation may be 900 m or more
below the surface. The injection
wells may be vertical, slanted, or directionally steered wells with a
significant horizontal or near horizontal portion.
The carbon dioxide and/or hydrogen sulfide may be introduced into the
formation near the bottom of the saline
aquifer.
Injection of carbon dioxide and/or hydrogen sulfide into a non-producing
formation or using the carbon
dioxide and/or hydrogen sulfide as a flood fluid is described by Caroll in
"Physical Properties Relevant to Acid Gas
Injection," Presented at the 14th International Gas Convention Venezuelan Gas
Processors Association on May 10-
12, 2000 in Caracas, Venezuela; "Phase Equilibria Relevant to Acid Gas
Injection: Part 1-Non-Aqueoues Phase
Behaviour Journal of Canadian Petroleum Technology, 2002, Vol. 41 No.6, pp. 1-
6; and "Phase Equilibria Relevant
to Acid Gas Injection: Part 2-Aqueoues Phase Behaviour Journal of Canadian
Petroleum Technology, 2002, Vol. 41,
No.7, pp.1-5, all of which are incorporated by reference as if fully set forth
herein.
During production of formation fluids from a subsurface formation, carbonic
acid may be produced from
the reaction of carbon dioxide with water. Portions of wells made of certain
materials, such as carbon steel, may
start to deteriorate or corrode in the presence of the carbonic acid. To
inhibit corrosion due to carbonic acid, basic
solutions and/or solvents may be introduced in the wellbore to neutralize
and/or dissolve the carbonic acid.
In some embodiments, hydrogen sulfide is introduced into one or more wellbores
in a subsurface formation.
Introduction of the hydrogen sulfide may be performed at pressures below the
lithostatic pressure of the subsurface
formation to inhibit fracturing the formation. The injected hydrogen sulfide
may form a sulfide layer on metal
surfaces of the well. Formation of a sulfide layer may inhibit corrosion of
the metal surfaces of the well by carbonic
acid.
In certain embodiments, an electrical insulator (for example, a centralizer,
an insulating layer, the electrical
insulator in an insulated conductor heater, or any other electrical insulator
described herein) includes a material that
is fired or cured when heated in the subsurface. The material may develop
desired dielectric or other electrical
properties and/or physical properties after the material is fired or cured in
a wellbore in the formation. The material
may be fired or cured when a heater is turned on in the wellbore and the
heater heats the material to its firing or
curing temperature.
An example of such a material is a ceramic tape available from Composite
Development Technology, Inc.
(Lafayette, Colorado, U.S.A.). The ceramic tape is flexible before it is
fired. The ceramic tape obtains its dielectric
properties after firing. After firing, the ceramic tape is a hard-ceramic with
good dielectric properties suitable for
subsurface electrical heating.
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In an embodiment, the ceramic tape is wrapped around an electrical conductor
(for example, the conductor
of a temperature limited heater). Electrical current may be applied to the
electrical conductor to heat the heater and
fire the ceramic tape. In some embodiments, the ceramic tape is pre-fired
before installation of a heater. The
ceramic tape may be pre-fired using, for example, a hot gas gun.
Before firing, the ceramic tape is flexible and easy to install in a variety
of applications. In certain
embodiments, the ceramic tape is used between centralizers in a conductor-in-
conduit heater. The ceramic tape may
inhibit shorting of the conductor and conduit if the centralizers fail (for
example, if the centralizers buckle and fail).
In certain embodiments, the ceramic tape is used as the centralizers in a
conductor-in-conduit heater. In some
embodiments, the ceramic tape is used as the electrical insulator in an
insulated conductor heater. In some
embodiments, the ceramic tape is used as the electrical insulator in splices
between sections of heaters. In some
embodiments, the ceramic tape is used to electrically insulate the legs of a
three-phase heater. The three legs of the
three-phase heater may be enclosed in one sheath with the ceramic tape
separating the legs of the heater.
Non-restrictive examples are set forth below.
Temperature Limited Heater Experimental Data
FIGS. 148-163 depict experimental data for temperature limited heaters. FIG.
148 depicts electrical
resistance (CI) versus temperature ( C) at various applied electrical currents
for a 446 stainless steel rod with a
diameter of 2.5 cm and a 410 stainless steel rod with a diameter of 2.5 cm.
Both rods had a length of 1.8 m. Curves
964-970 depict resistance profiles as a function of temperature for the 446
stainless steel rod at 440 amps AC (curve
964), 450 amps AC (curve 966), 500 amps AC (curve 968), and 10 amps DC (curve
970). Curves 972-978 depict
resistance profiles as a function of temperature for the 410 stainless steel
rod at 400 amps AC (curve 972), 450 amps
AC (curve 974), 500 amps AC (curve 976), 10 amps DC (curve 978). For both
rods, the resistance gradually
increased with temperature until the Curie temperature was reached. At the
Curie temperature, the resistance fell
sharply. Above the Curie temperature, the resistance decreased slightly with
increasing temperature. Both rods
show a trend of decreasing resistance with increasing AC current. Accordingly,
the turndown ratio decreased with
increasing current. Thus, the rods provide a reduced amount of heat near and
above the Curie temperature of the
rods. In contrast, the resistance gradually increased with temperature through
the Curie temperature with the applied
DC current.
FIG. 149 shows electrical resistance (S1) profiles as a function of
temperature ( C) at various applied
electrical currents for a copper rod contained in a conduit of Sumitomo HCM12A
(a high strength 410 stainless
steel). The Sumitomo conduit had a diameter of 5.1 cm, a length of 1.8 m, and
a wall thickness of about 0.1 cm.
Curves 980-990 show that at all applied currents (980: 300 amps AC; 982: 350
amps AC; 984: 400 amps AC; 986:
450 amps AC; 988: 500 amps AC; 990: 550 amps AC), resistance increased
gradually with temperature until the
Curie temperature was reached. At the Curie temperature, the resistance fell
sharply. As the current increased, the
resistance decreased, resulting in a smaller turndown ratio.
FIG. 150 depicts electrical resistance (0) versus temperature ( C) at various
applied electrical currents for a
temperature limited heater. The temperature limited heater included a 4/0 MGT-
1000 furnace cable inside an outer
conductor of 1/4" Schedule 80 Sandvik (Sweden) 4C54 (446 stainless steel) with
a 0.30 cm thick copper sheath
welded onto the outside of the Sandvik 4C54 and a length of 1.8 m. Curves 1000
through 1018 show resistance
profiles as a function of temperature for AC applied currents ranging from 40
amps to 500 amps (1000: 40 amps;
1002: 80 amps; 1004: 120 amps; 1006: 160 amps; 1008: 250 amps; 1010: 300 amps;
1012: 350 amps; 1014: 400
amps; 1016: 450 amps; 1018: 500 amps). FIG. 151 depicts the raw data for curve
1014. FIG. 152 depicts the data
for selected curves 1010, 1012, 1014, 1016, 1018, and 1020. At lower currents
(below 250 amps), the resistance
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increased with increasing temperature up to the Curie temperature. At the
Curie temperature, the resistance fell
sharply. At higher currents (above 250 amps), the resistance decreased
slightly with increasing temperature up to the
Curie temperature. At the Curie temperature, the resistance fell sharply.
Curve 1020 shows resistance for an applied
DC electrical current of 10 amps. Curve 1020 shows a steady increase in
resistance with increasing temperature,
with little or no deviation at the Curie temperature.
FIG. 153 depicts power (watts per meter (W/m)) versus temperature ( C) at
various applied electrical
currents for a temperature limited heater. The temperature limited heater
included a 4/0 MGT-1000 furnace cable
inside an outer conductor of 3/4 Schedule 80 Sandvik (Sweden) 4C54 (446
stainless steel) with a 0.30 cm thick
copper sheath welded onto the outside of the Sandvik 4C54 and a length of 1.8
m. Curves 1022-1030 depict power
versus temperature for AC applied currents of 300 amps to 500 amps (1022: 300
amps; 1024: 350 amps; 1026: 400
amps; 1028: 450 amps; 1030: 500 amps). Increasing the temperature gradually
decreased the power until the Curie
temperature was reached. At the Curie temperature, the power decreased
rapidly.
FIG. 154 depicts electrical resistance (me) versus temperature ( C) at various
applied electrical currents for
a temperature limited heater. The temperature limited heater included a copper
rod with a diameter of 1.3 cm inside
an outer conductor of 2.5 cm Schedule 80 410 stainless steel pipe with a 0.15
cm thick copper EverdurTM (DuPont
Engineering, Wilmington, Delaware, U.S.A.) welded sheath over the 410
stainless steel pipe and a length of 1.8 m.
Curves 1032-1042 show resistance profiles as a function of temperature for AC
applied currents ranging from 300
amps to 550 amps (1032: 300 amps; 1034: 350 amps; 1036: 400 amps; 1038: 450
amps; 1040: 500 amps; 1042: 550
amps). For these AC applied currents, the resistance gradually increases with
increasing temperature up to the Curie
temperature. At the Curie temperature, the resistance falls sharply. In
contrast, curve 1044 shows resistance for an
applied DC electrical current of 10 amps. This resistance shows a steady
increase with increasing temperature, and
little or no deviation at the Curie temperature.
FIG. 155 depicts data of electrical resistance (me) versus temperature ( C)
for a solid 2.54 cm diameter,
1.8 m long 410 stainless steel rod at various applied electrical currents.
Curves 1046, 1048, 1050, 1052, and 1054
depict resistance profiles as a function of temperature for the 410 stainless
steel rod at 40 amps AC (curve 1052), 70
amps AC (curve 1054), 140 amps AC (curve 1046), 230 amps AC (curve 1048), and
10 amps DC (curve 1050). For
the applied AC currents of 140 amps and 230 amps, the resistance increased
gradually with increasing temperature
until the Curie temperature was reached. At the Curie temperature, the
resistance fell sharply. In contrast, the
resistance showed a gradual increase with temperature through the Curie
temperature for the applied DC current.
FIG. 156 depicts data of electrical resistance (ma) versus temperature ( C)
for a composite 1.75 inch (1.9
cm) diameter, 6 foot (1.8 m) long Alloy 42-6 rod with a 0.375 inch diameter
copper core (the rod has an outside
diameter to copper diameter ratio of 2:1) at various applied electrical
currents. Curves 1056, 1058, 1060, 1062,
1064, 1066, 1068, and 1070 depict resistance profiles as a function of
temperature for the copper cored alloy 42-6
rod at 300 A AC (curve 1056), 350 A AC (curve 1058), 400 A AC (curve 1060),
450 A AC (curve 1062), 500 A AC
(curve 1064), 550 A AC (curve 1066), 600 A AC (curve 1068), and 10 A DC (curve
1070). For the applied AC
currents, the resistance decreased gradually with increasing temperature until
the Curie temperature was reached. As
the temperature approaches the Curie temperature, the resistance decreased
more sharply. In contrast, the resistance
showed a gradual increase with temperature for the applied DC current.
FIG. 157 depicts data of power output (watts per foot (W/ft)) versus
temperature ( C) for a composite 1.75
inch (1.9 cm) diameter, 6 foot (1.8 m) long Alloy 42-6 rod with a 0.375 inch
diameter copper core (the rod has an
outside diameter to copper diameter ratio of 2:1) at various applied
electrical currents. Curves 1072, 1074, 1076,
1078, 1080, 1082, 1084, and 1086 depict power as a function of temperature for
the copper cored alloy 42-6 rod at
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300 A AC (curve 1072), 350 A AC (curve 1074), 400 A AC (curve 1076), 450 A AC
(curve 1078), 500 A AC (curve
1080), 550 A AC (curve 1082), 600 A AC (curve 1084), and 10 A DC (curve 1086).
For the applied AC currents,
the power output decreased gradually with increasing temperature until the
Curie temperature was reached. As the
temperature approaches the Curie temperature, the power output decreased more
sharply. In contrast, the power
output showed a relatively flat profile with temperature for the applied DC
current.
FIG. 158 depicts data for values of skin depth (cm) versus temperature ( C)
for a solid 2.54 cm diameter,
1.8 m long 410 stainless steel rod at various applied AC electrical currents.
The skin depth was calculated using
EQN. 9:
(9) = R1 - Ri x (1 - (1 /RAc/RDc)) I /2;
where 8 is the skin depth, R1 is the radius of the cylinder, RAC is the AC
resistance, and Rix is the DC resistance. In
FIG. 158, curves 1088-1106 show skin depth profiles as a function of
temperature for applied AC electrical currents
over a range of 50 amps to 500 amps (1088: 50 amps; 1090: 100 amps; 1092: 150
amps; 1094: 200 amps; 1096: 250
amps; 1098: 300 amps; 1100: 350 amps; 1102: 400 amps; 1104: 450 amps; 1106:
500 amps). For each applied AC
electrical current, the skin depth gradually increased with increasing
temperature up to the Curie temperature. At the
Curie temperature, the skin depth increased sharply.
FIG. 159 depicts temperature ( C) versus time (hrs) for a temperature limited
heater. The temperature
limited heater was a 1.83 m long heater that included a copper rod with a
diameter of 1.3 cm inside a 2.5 cm
Schedule XXH 410 stainless steel pipe and a 0.325 cm copper sheath. The heater
was placed in an oven for heating.
Alternating current was applied to the heater when the heater was in the oven.
The current was increased over two
hours and reached a relatively constant value of 400 amps for the remainder of
the time. Temperature of the
stainless steel pipe was measured at three points at 0.46 m intervals along
the length of the heater. Curve 1108
depicts the temperature of the pipe at a point 0.46 m inside the oven and
closest to the lead-in portion of the heater.
Curve 1110 depicts the temperature of the pipe at a point 0.46 m from the end
of the pipe and furthest from the lead-
in portion of the heater. Curve 1112 depicts the temperature of the pipe at
about a center point of the heater. The
point at the center of the heater was further enclosed in a 0.3 m section of
2.5 cm thick Fiberfrax (Unifrax Corp.,
Niagara Falls, New York, U.S.A.) insulation. The insulation was used to create
a low thermal conductivity section
on the heater (a section where heat transfer to the surroundings is slowed or
inhibited (a "hot spot")). The
temperature of the heater increased with time as shown by curves 1112, 1110,
and 1108. Curves 1112, 1110, and
1108 show that the temperature of the heater increased to about the same value
for all three points along the length
of the heater. The resulting temperatures were substantially independent of
the added Fiberfrax insulation. Thus,
the operating temperatures of the temperature limited heater were
substantially the same despite the differences in
thermal load (due to the insulation) at each of the three points along the
length of the heater. Thus, the temperature
limited heater did not exceed the selected temperature limit in the presence
of a low thermal conductivity section.
FIG. 160 depicts temperature ( C) versus log time (hrs) data for a 2.5 cm
solid 410 stainless steel rod and a
2.5 cm solid 304 stainless steel rod. At a constant applied AC electrical
current, the temperature of each rod
increased with time. Curve 1114 shows data for a thermocouple placed on an
outer surface of the 304 stainless steel
rod and under a layer of insulation. Curve 1116 shows data for a thermocouple
placed on an outer surface of the 304
stainless steel rod without a layer of insulation. Curve 1118 shows data for a
thermocouple placed on an outer
surface of the 410 stainless steel rod and under a layer of insulation. Curve
1120 shows data for a thermocouple
placed on an outer surface of the 410 stainless steel rod without a layer of
insulation. A comparison of the curves
shows that the temperature of the 304 stainless steel rod (curves 1114 and
1116) increased more rapidly than the
temperature of the 410 stainless steel rod (curves 1118 and 1120). The
temperature of the 304 stainless steel rod
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(curves 1114 and 1116) also reached a higher value than the temperature of the
410 stainless steel rod (curves 1118
and 1120). The temperature difference between the non-insulated section of the
410 stainless steel rod (curve 1120)
and the insulated section of the 410 stainless steel rod (curve 1118) was less
than the temperature difference between
the non-insulated section of the 304 stainless steel rod (curve 1116) and the
insulated section of the 304 stainless
steel rod (curve 1114). The temperature of the 304 stainless steel rod was
increasing at the termination of the
experiment (curves 1114 and 1116) while the temperature of the 410 stainless
steel rod had leveled out (curves 1118
and 1120). Thus, the 410 stainless steel rod (the temperature limited heater)
provided better temperature control than
the 304 stainless steel rod (the non-temperature limited heater) in the
presence of varying thermal loads (due to the
insulation).
A 6 foot temperature limited heater element was placed in a 6 foot 347H
stainless steel canister. The heater
element was connected to the canister in a series configuration. The heater
element and canister were placed in an
oven. The oven was used to raise the temperature of the heater element and the
canister. At varying temperatures, a
series of electrical currents were passed through the heater element and
returned through the canister. The resistance
of the heater element and the power factor of the heater element were
determined from measurements during passing
of the electrical currents.
FIG. 161 depicts experimentally measured electrical resistance (me) versus
temperature ( C) at several
currents for a temperature limited heater with a copper core, a carbon steel
ferromagnetic conductor, and a 347H
stainless steel support member. The ferromagnetic conductor was a low-carbon
steel with a Curie temperature of
770 C. The ferromagnetic conductor was sandwiched between the copper core and
the 347H support member. The
copper core had a diameter of 0.5". The ferromagnetic conductor had an outside
diameter of 0.765". The support
member had an outside diameter of 1.05". The canister was a 3" Schedule 160
347H stainless steel canister.
Data 1122 depicts electrical resistance versus temperature for 300 A at 60 Hz
AC applied current. Data
1124 depicts resistance versus temperature for 400A at 60 Hz AC applied
current. Data 1126 depicts resistance
versus temperature for 500A at 60 Hz AC applied current. Curve 1128 depicts
resistance versus temperature for
10A DC applied current. The resistance versus temperature data indicates that
the AC resistance of the temperature
limited heater linearly increased up to a temperature near the Curie
temperature of the ferromagnetic conductor.
Near the Curie temperature, the AC resistance decreased rapidly until the AC
resistance equaled the DC resistance
above the Curie temperature. The linear dependence of the AC resistance below
the Curie temperature at least
partially reflects the linear dependence of the AC resistance of 347H at these
temperatures. Thus, the linear
dependence of the AC resistance below the Curie temperature indicates that the
majority of the current is flowing
through the 347H support member at these temperatures.
FIG. 162 depicts experimentally measured electrical resistance (me) versus
temperature ( C) data at
several currents for a temperature limited heater with a copper core, a iron-
cobalt ferromagnetic conductor, and a
347H stainless steel support member. The iron-cobalt ferromagnetic conductor
was an iron-cobalt conductor with
6% cobalt by weight and a Curie temperature of 834 C. The ferromagnetic
conductor was sandwiched between the
copper core and the 347H support member. The copper core had a diameter of
0.465". The ferromagnetic conductor
had an outside diameter of 0.765". The support member had an outside diameter
of 1.05". The canister was a 3"
Schedule 160 347H stainless steel canister.
Data 1130 depicts resistance versus temperature for 100 A at 60 Hz AC applied
current. Data 1132 depicts
resistance versus temperature for 400 A at 60 Hz AC applied current. Curve
1134 depicts resistance versus
temperature for 10A DC. The AC resistance of this temperature limited heater
turned down at a higher temperature
than the previous temperature limited heater. This was due to the added cobalt
increasing the Curie temperature of
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the ferromagnetic conductor. The AC resistance was substantially the same as
the AC resistance of a tube of 347H
steel having the dimensions of the support member. This indicates that the
majority of the current is flowing through
the 347H support member at these temperatures. The resistance curves in FIG.
162 are generally the same shape as
the resistance curves in FIG. 161.
FIG. 163 depicts experimentally measured power factor (y-axis) versus
temperature ( C) at two AC
currents for the temperature limited heater with the copper core, the iron-
cobalt ferromagnetic conductor, and the
347H stainless steel support member. Curve 1136 depicts power factor versus
temperature for 100A at 60 Hz AC
applied current. Curve 1138 depicts power factor versus temperature for 400A
at 60 Hz AC applied current. The
power factor was close to unity (1) except for the region around the Curie
temperature. In the region around the
Curie temperature, the non-linear magnetic properties and a larger portion of
the current flowing through the
ferromagnetic conductor produce inductive effects and distortion in the heater
that lowers the power factor. FIG.
163 shows that the minimum value of the power factor for this heater remained
above 0.85 at all temperatures in the
experiment. Because only portions of the temperature limited heater used to
heat a subsurface formation may be at
the Curie temperature at any given point in time and the power factor for
these portions does not go below 0.85
during use, the power factor for the entire temperature limited heater would
remain above 0.85 (for example, above
0.9 or above 0.95) during use.
From the data in the experiments for the temperature limited heater with the
copper core, the iron-cobalt
ferromagnetic conductor, and the 347H stainless steel support member, the
turndown ratio (y-axis) was calculated as
a function of the maximum power (W/m) delivered by the temperature limited
heater. The results of these
calculations are depicted in FIG. 164. The curve in FIG. 164 shows that the
turndown ratio (y-axis) remains above 2
for heater powers up to approximately 2000 W/m. This curve is used to
determine the ability of a heater to
effectively provide heat output in a sustainable manner. A temperature limited
heater with the curve similar to the
curve in FIG. 164 would be able to provide sufficient heat output while
maintaining temperature limiting properties
that inhibit the heater from overheating or malfunctioning.
A theoretical model has been used to predict the experimental results. The
theoretical model is based on an
analytical solution for the AC resistance of a composite conductor. The
composite conductor has a thin layer of
ferromagnetic material, with a relative magnetic permeability 112/11.0>> 1,
sandwiched between two non-
ferromagnetic materials, whose relative magnetic permeabilities, 1410 and p3/
0, are close to unity and within which
skin effects are negligible. An assumption in the model is that the
ferromagnetic material is treated as linear. In
addition, the way in which the relative magnetic permeability, 1.12/1.10, is
extracted from magnetic data for use in the
model is far from rigorous.
Magnetic data was obtained for carbon steel as a ferromagnetic material. B
versus H curves, and hence
relative permeabilities, were obtained from the magnetic data at various
temperatures up to 1100 F and magnetic
fields up to 200 Oe (oersteds). A correlation was found that fitted the data
well through the maximum permeability
and beyond. FIG. 165 depicts examples of relative magnetic permeability (y-
axis) versus magnetic field (Oe) for
both the found correlations and raw data for carbon steel. Data 1140 is raw
data for carbon steel at 400 F. Data
1142 is raw data for carbon steel at 1000 F. Curve 1144 is the found
correlation for carbon steel at 400 F. Curve
1146 is the found correlation for carbon steel at 1000 F.
For the dimensions and materials of the copper/carbon steel/347H heater
element in the experiments above,
theoretical calculations were carried out to calculate magnetic field at the
outer surface of the carbon steel as a
function of skin depth. Results of the theoretical calculations were presented
on the same plot as skin depth versus
magnetic field from the correlations applied to the magnetic data from FIG.
165. The theoretical calculations and
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correlations were made for four temperatures (200 F, 500 F, 800 F, and 1100
F) and five total root-mean-square
(RMS) currents (100 A, 200 A, 300 A, 400 A, and 500 A).
FIG. 166 shows the resulting plots of skin depth (in) versus magnetic field
(Oe) for all four temperatures
and 400 A current. Curve 1148 is the correlation from magnetic data at 200 F.
Curve 1150 is the correlation from
magnetic data at 500 F. Curve 1152 is the correlation from magnetic data at
800 F. Curve 1154 is the correlation
from magnetic data at 1100 F. Curve 1156 is the theoretical calculation at
the outer surface of the carbon steel as a
function of skin depth at 200 F. Curve 1158 is the theoretical calculation at
the outer surface of the carbon steel as a
function of skin depth at 500 F. Curve 1160 is the theoretical calculation at
the outer surface of the carbon steel as a
function of skin depth at 800 F. Curve 1162 is the theoretical calculation at
the outer surface of the carbon steel as a
function of skin depth at 1100 F.
The skin depths obtained from the intersections of the same temperature curves
in FIG. 166 were input into
equations based on theory and the AC resistance per unit length was
calculated. The total AC resistance of the entire
heater, including that of the canister, was subsequently calculated. A
comparison between the experimental and
numerical (calculated) results is shown in FIG. 167 for currents of 300 A
(experimental data 1164 and numerical
curve 1166), 400A (experimental data 1168 and numerical curve 1170), and 500 A
(experimental data 1172 and
numerical curve 1174). Though the numerical results exhibit a steeper trend
than the experimental results, the
theoretical model captures the close bunching of the experimental data, and
the overall values are quite reasonable
given the assumptions involved in the theoretical model. For example, one
assumption involved the use of a
permeability derived from a quasistatic B-H curve to treat a dynamic system.
One feature of the theoretical model describing the flow of alternating
current in the three-part temperature
limited heater is that the AC resistance does not fall off monotonically with
increasing skin depth. FIG. 168 shows
the AC resistance (me) per foot of the heater element as a function of skin
depth (in.) at 1100 F calculated from the
theoretical model. The AC resistance may be maximized by selecting the skin
depth that is at the peak of the non-
monotonical portion of the resistance versus skin depth profile (for example,
at about 0.23 in. in FIG. 168).
FIG. 169 shows the power generated per unit length (W/ft) in each heater
component (curve 1176 (copper
core), curve 1178 (carbon steel), curve 1180 (347H outer layer), and curve
1182 (total)) versus skin depth (in.). As
expected, the power dissipation in the 347H falls off while the power
dissipation in the copper core increases as the
skin depth increases. The maximum power dissipation in the carbon steel occurs
at the skin depth of about 0.23
inches and is expected to correspond to the minimum in the power factor, as
shown in FIG. 163. The current density
in the carbon steel behaves like a damped wave of wavelength X = 2n6 and the
effect of this wavelength on the
boundary conditions at the copper/carbon steel and carbon steel/347H interface
may be behind the structure in FIG.
168. For example, the local minimum in AC resistance is close to the value at
which the thickness of the carbon
steel layer corresponds to X/4. Formulae may be developed that describe the
shapes of the AC resistance versus
temperature profiles of temperature limited heaters for use in simulating the
performance of the heaters in a
particular embodiment. The data in FIGS. 161 and 162 show that the resistances
initially rise linearly, then drop off
increasingly steeply towards the DC lines.
FIGS. 170 A-C compare the results of the theoretical calculations with
experimental data at 300A (FIG.
170A), 400 A (FIG. 170B) and 500 A (FIG. 170C). FIG. 170A depicts electrical
resistance (me) versus temperature
( F) at 300 A. Data 1184 is the experimental data at 300 A. Curve 1186 is the
theoretical calculation at 300 A.
Curve 1188 is a plot of resistance versus temperature at 10 A DC. FIG. 170B
depicts electrical resistance (me)
versus temperature ( F) at 400 A. Data 1190 is the experimental data at 400 A.
Curve 1192 is the theoretical
calculation at 400 A. Curve 1194 is a plot of resistance versus temperature at
10 A DC. FIG. 170C depicts electrical
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resistance (mQ) versus temperature ( F) at 500 A. Data 1196 is the
experimental data at 500 A. Curve 1198 is the
theoretical calculation at 500 A. Curve 1200 is a plot of resistance versus
temperature at 10 A DC.
Temperature Limited Heater Simulations
A numerical simulation (FLUENT available from Fluent USA, Lebanon, New
Hampshire, U.S.A.) was
used to compare operation of temperature limited heaters with three turndown
ratios. The simulation was done for
heaters in an oil shale formation (Green River oil shale). Simulation
conditions were:
- 61 m length conductor-in-conduit temperature limited heaters
(center conductor (2.54 cm
diameter), conduit outer diameter 7.3 cm)
- downhole heater test field richness profile for an oil shale
formation
- 16.5 cm (6.5 inch) diameter wellbores at 9.14 m spacing between wellbores
on triangular spacing
- 200 hours power ramp-up time to 820 watts/m initial heat
injection rate
- constant current operation after ramp up
- Curie temperature of 720.6 C for heater
- formation will swell and touch the heater canisters for oil
shale richnesses at least 0.14 L/kg (35
gals/ton)
FIG. 171 displays temperature ( C) of a center conductor of a conductor-in-
conduit heater as a function of
formation depth (m) for a temperature limited heater with a turndown ratio of
2:1. Curves 1202-1224 depict
temperature profiles in the formation at various times ranging from 8 days
after the start of heating to 675 days after
the start of heating (1202: 8 days, 1204: 50 days, 1206: 91 days, 1208: 133
days, 1210: 216 days, 1212: 300 days,
1214: 383 days, 1216: 466 days, 1218: 550 days, 1220: 591 days, 1222: 633
days, 1224: 675 days). At a turndown
ratio of 2:1, the Curie temperature of 720.6 C was exceeded after 466 days in
the richest oil shale layers. FIG. 172
shows the corresponding heater heat flux (W/m) through the formation for a
turndown ratio of 2:1 along with the oil
shale richness (1/kg) profile (curve 1226). Curves 1228-1260 show the heat
flux profiles at various times from 8
days after the start of heating to 633 days after the start of heating (1228:
8 days; 1230: 50 days; 1232: 91 days;
1234: 133 days; 1238: 175 days; 1240: 216 days; 1242: 258 days; 1244: 300
days; 1236: 341 days; 1246: 383 days;
1248: 425 days; 1250: 466 days; 1252: 508 days; 1254: 550 days; 1256: 591
days; 1258: 633 days; 1260: 675 days).
At a turndown ratio of 2:1, the center conductor temperature exceeded the
Curie temperature in the richest oil shale
layers.
FIG. 173 displays heater temperature ( C) as a function of formation depth (m)
for a turndown ratio of 3:1.
Curves 1262-1284 show temperature profiles through the formation at various
times ranging from 12 days after the
start of heating to 703 days after the start of heating (1262: 12 days; 1264:
33 days; 1266: 62 days; 1268: 102 days;
1270: 146 days; 1272: 205 days; 1274: 271 days; 1276: 354 days; 1278: 467
days; 1280: 605 days; 1282: 662 days;
1284: 703 days). At a turndown ratio of 3:1, the Curie temperature was
approached after 703 days. FIG. 174 shows
the corresponding heater heat flux (W/m) through the formation for a turndown
ratio of 3:1 along with the oil shale
richness (1/kg) profile (curve 1286). Curves 1288-1308 show the heat flux
profiles at various times from 12 days
after the start of heating to 605 days after the start of heating (1288: 12
days, 1290: 32 days, 1292: 62 days, 1294:
102 days, 1296: 146 days, 1298: 205 days, 1300: 271 days, 1302: 354 days,
1304: 467 days, 1306: 605 days, 1308:
749 days). The center conductor temperature never exceeded the Curie
temperature for the turndown ratio of 3:1.
The center conductor temperature also showed a relatively flat temperature
profile for the 3:1 turndown ratio.
FIG. 175 shows heater temperature ( C) as a function of formation depth (m)
for a turndown ratio of 4:1.
Curves 1310-1330 show temperature profiles through the formation at various
times ranging from 12 days after the
start of heating to 467 days after the start of heating (1310: 12 days; 1312:
33 days; 1314: 62 days; 1316: 102 days,
177
CA 02871784 2014-11-18
1318: 147 days; 1320: 205 days; 1322: 272 days; 1324: 354 days; 1326: 467
days; 1328: 606 days, 1330: 678 days).
At a turndown ratio of 4:1, the Curie temperature was not exceeded even after
678 days. The center conductor
temperature never exceeded the Curie temperature for the turndown ratio of
4:1. The center conductor showed a
temperature profile for the 4:1 turndown ratio that was somewhat flatter than
the temperature profile for the 3:1
turndown ratio. These simulations show that the heater temperature stays at or
below the Curie temperature for a
longer time at higher turndown ratios. For this oil shale richness profile, a
turndown ratio of at least 3:1 may be
desirable.
Simulations have been performed to compare the use of temperature limited
heaters and non-temperature
limited heaters in an oil shale formation. Simulation data was produced for
conductor-in-conduit heaters placed in
16.5 cm (6.5 inch) diameter wellbores with 12.2 m (40 feet) spacing between
heaters using a formation simulator
(for example, STARS) and a near wellbore simulator (for example, ABAQUS from
ABAQUS, Inc., Providence,
Rhode Island, U.S.A.). Standard conductor-in-conduit heaters included 304
stainless steel conductors and conduits.
Temperature limited conductor-in-conduit heaters included a metal with a Curie
temperature of 760 C for
conductors and conduits. Results from the simulations are depicted in FIGS.
176-178.
FIG. 176 depicts heater temperature ( C) at the conductor of a conductor-in-
conduit heater versus depth (m)
of the heater in the formation for a simulation after 20,000 hours of
operation. Heater power was set at 820
watts/meter until 760 C was reached, and the power was reduced to inhibit
overheating. Curve 1332 depicts the
conductor temperature for standard conductor-in-conduit heaters. Curve 1332
shows that a large variance in
conductor temperature and a significant number of hot spots developed along
the length of the conductor. The
temperature of the conductor had a minimum value of 490 C. Curve 1334 depicts
conductor temperature for
temperature limited conductor-in-conduit heaters. As shown in FIG. 176,
temperature distribution along the length
of the conductor was more controlled for the temperature limited heaters. In
addition, the operating temperature of
the conductor was 730 C for the temperature limited heaters. Thus, more heat
input would be provided to the
formation for a similar heater power using temperature limited heaters.
FIG. 177 depicts heater heat flux (W/m) versus time (yrs) for the heaters used
in the simulation for heating
oil shale. Curve 1336 depicts heat flux for standard conductor-in-conduit
heaters. Curve 1338 depicts heat flux for
temperature limited conductor-in-conduit heaters. As shown in FIG. 177, heat
flux for the temperature limited
heaters was maintained at a higher value for a longer period of time than heat
flux for standard heaters. The higher
heat flux may provide more uniform and faster heating of the formation.
FIG. 178 depicts cumulative heat input (kJ/m)(kilojoules per meter) versus
time (yrs) for the heaters used in
the simulation for heating oil shale. Curve 1340 depicts cumulative heat input
for standard conductor-in-conduit
heaters. Curve 1342 depicts cumulative heat input for temperature limited
conductor-in-conduit heaters. As shown
in FIG. 178, cumulative heat input for the temperature limited heaters
increased faster than cumulative heat input for
standard heaters. The faster accumulation of heat in the formation using
temperature limited heaters may decrease
the time needed for retorting the formation. Onset of retorting of the oil
shale formation may begin around an
average cumulative heat input of 1.1 x 108 kJ/meter. This value of cumulative
heat input is reached around 5 years
for temperature limited heaters and between 9 and 10 years for standard
heaters.
Triad Pattern Heater Simulation
FIG. 179 depicts cumulative gas production and cumulative oil production
versus time (years) found from a
STARS simulation (Computer Modelling Group, LTD., Calgary, Alberta, Canada)
using the temperature limited
heaters and heater pattern depicted in FIGS. 65 and 67. Curve 1344 depicts
cumulative oil production (m3) for an
initial water saturation of 15%. Curve 1346 depicts cumulative gas production
(m3) for the initial water saturation of
178
CA 02871784 2014-11-18
15%. Curve 1348 depicts cumulative oil production (m3) for an initial water
saturation of 85%. Curve 1350 depicts
cumulative gas production (m3) for the initial water saturation of 85%. As
shown by the small differences between
curves 1344 and 1348 for cumulative oil production and curves 1346 and 1350
for cumulative gas production, the
initial water saturation does not substantially alter heating of the
formation. As a result, the overall production of
hydrocarbons from the formation is also not substantially changed by the
initial water saturation. Using the
temperature limited heaters inhibits variances in heating of the formation
that otherwise may be caused by the
differences in the initial water saturation.
Phase Transformation and Curie Temperature Experimental Calculations
FIG. 180 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for iron alloy TC3 (0.1% by weight carbon, 5% by weight cobalt,
12% by weight chromium, 0.5% by
weight manganese, 0.5% by weight silicon). Curve 1352 depicts weight
percentage of the ferrite phase. Curve 1354
depicts weight percentage of the austenite phase. The arrow points to the
Curie temperature of the alloy. As shown
in FIG. 180, the phase transformation was close to the Curie temperature but
did not overlap with the Curie
temperature for this alloy.
FIG. 181 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for iron alloy FM-4 (0.1% by weight carbon, 5% by weight cobalt,
0.5% by weight manganese, 0.5% by
weight silicon). Curve 1356 depicts weight percentage of the ferrite phase.
Curve 1358 depicts weight percentage
of the austenite phase. The arrow points to the Curie temperature of the
alloy. As shown in FIG. 181, the phase
transformation broadened without chromium in the alloy and the phase
transformation overlapped with the Curie
temperature for this alloy.
FIG. 181 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for iron alloy FM-4 (0.1% by weight carbon, 5% by weight cobalt,
0.5% by weight manganese, 0.5% by
weight silicon). Curve 1356 depicts weight percentage of the ferrite phase.
Curve 1358 depicts weight percentage
of the austenite phase. The arrow points to the Curie temperature of the
alloy. As shown in FIG. 181, the phase
transformation broadened without chromium in the alloy and the phase
transformation overlapped with the Curie
temperature for this alloy.
Calculations for the Curie temperature (TO and the phase transformation
behavior were done for various
mixtures of cobalt, carbon, manganese, silicon, vanadium, and titanium using
computational thermodynamic
software (ThermoCalc and JMatPro obtained from Thermo-Calc Software, Inc.,
(McMurray, PA, U.S.A)) to predict
the effect of additional elements on Curie Temperature (TO for selected
compositions, the temperature (A1) at which
ferrite transforms to paramagnetic austenite, and the phases present at those
temperatures. An equilibrium
calculation temperature of 700 C was used in all calculations. As shown in
TABLE 2, as the weight percentage of
cobalt in the composition increased, T, and Al increased; however, Tc remained
above Al. An increase in the A1
temperature may be predicted upon sufficient addition of carbide formers
vanadium, titanium, niobium, tantalum,
and tungsten. For example, about 0.5% by weight of carbide formers may be used
in an alloy that includes about
0.1% by weight of carbon. Addition of carbide formers allows replacement of
the Fe3C carbide phase with a MC
carbide phase. From the calculations, excess amounts of vanadium appeared to
not have an impact on Tõ while
excess amounts of other carbide formers reduced the T.
179
CA 02871784 2014-11-18
TABLE 2
Composition ( /0 by weight, balance being Fe) Calculation Results
____________________________________________________________________________ -
Co C Mn Si V Ti T. (EC) A1 (EC) Phases Present (-
700EC)
0 0.1 0.5 , 0.5 0 0 758 716 ferrite + Fe3C
(FM2)
2 0.1 0.5 0.5 0 0 776 726 ferrite + Fe3C (FM4)
0.1 0.5 0.5 0 0 803 740 , ferrite + Fe3C (FM6)
_ ___________________________________________________________________________
8 0.1 0.5 0.5 0 0 829 752 ferrite + Fe3C (FM8)
5 0.1 0.5 0.5 0.2 0 803 740 ferrite + Fe3C + VC
5 0.1 0.5 0.5 0.4 0 802 773 ferrite + Fe3C + VC
5 0.1 0.5 0.5 0.5 0 802 830 ferrite + VC
-4 ____________________ . ___________________ - _____
5 0.1 0.5 0.5 0.6 0 802 855 ferrite + VC
5 0.1 0.5 0.5 0.8 0 803 880 ferrite + VC
5 0.1 0.5 , 0.5 1.0 0 805 896 ferrite
+ VC
5 0.1 0.5 0.5 1.5 0 807 928 ferrite + VC
,
5 0.1 0.5 0.5 2.0 0 810 959 ferrite + VC
6 0.1 0.5 0.5 0.5 0 811 835 ferrite + VC
____________________________________________________________________________ i
7 0.1 0.5 0.5 0.5 0 819 839 ferrite + VC
________________ i _________________________________________________________
8 0.1 0.5 0.5 0.5 0 828 843 ferrite + VC
9 0.1 0.5 0.5 0.5 0 836 847 ferrite + VC
0.1 0.5 0.5 0.5 0 845 852 ferrite + VC
11 0.1 0.5 0.5 0.5 0 853 856 ferrite + VC
12 0.1 0.5 0.5 0.5 0 861 859 ferrite + VC
10 0.1 0.5 0.5 1.0 0 847 907 ferrite + VC
11 0.1 0.5 0.5 1.0 0 855 . 909 ferrite + VC
12 0.1 0.5 , 0.5 1.0 0 863 911 ferrite
+ VC
, 13 0.1 0.5 0.5 1.0 0 871 913 ferrite
+ VC
14 0.1 0.5 0.5 1.0 0 879 915 ferrite + VC
0.1 0.5 0.5 1.0 0 886 917 ferrite + VC
17 0.1 0.5 0.5 1.0 0 902 920 ferrite + VC
0.1 0.5 0.5 1.0 0 924 926 ferrite + VC
5 0.1 0.5 0.5 0 0.2 802 738 ferrite + Fe3C + TiC
5 0.1 0.5 0.5 0 0.3 802 738 ferrite + Fe3C + TiC
5 0.1 0.5 0.5 0 0.4 802 867 ferrite + TIC
180
CA 02871784 2014-11-18
Composition (1)/0 by weight, balance being Fe) Calculation Results
Co C Mn Si V Ti T, (EC) AI (EC) Phases Present
(-700EC)
0.1 0.5 0.5 0 0.45 802 896 ferrite + TiC
5 0.1 0.5 0.5 0 0.5 801 902 ferrite + TiC
5 0.1 0.5 0.5 0 1.0 795 934 ferrite + TiC
8 0.1 0.5 0.5 0 0.5 827 905 ferrite + TiC
0.1 0.5 0.5 0 0.5 844 908 ferrite + TiC
11 0.1 0.5 0.5 0 0.5 852 909 ferrite + TiC
12 0.1 0.5 0.5 0 0.5 860 911 ferrite + TiC
13 0.1 0.5 0.5 0 0.5 868 912 ferrite + TiC
14 0.1 0.5 0.5 0 0.5 876 914 ferrite + TiC
0.1 0.5 0.5 0 0.5 884 915 ferrite + TiC
17 0.1 0.5 0.5 0 0.5 899 918 ferrite + TiC
_
18 0.1 0.5 0.5 0 0.5 907 920 ferrite + TiC
19 0.1 , 0.5 0.5 0 0.5 914 921 .. ferrite +
TiC
0.1 0.5 0.5 0 0.5 922 , 923 .. ferrite + TiC
21 0.1 0.5 0.5 0 0.5 929 924 ferrite + TiC
21 0.1 0.5 0.5 0 0.6 928 926 ferrite + TiC
21 0.1 0.5 0.5 0 0.7 926 928 ferrite + TiC
21 0.1 0.5 0.5 0 0.8 925 930 ferrite + TiC
21 0.1 0.5 0.5 0 1.0 922 934 ferrite + TiC
_. ___________________________________________________________________
22 0.1 0.5 0.5 0 1.0 930 935 ferrite + TiC
23 0.1 0.5 0.5 0 1.0 937 936 ferrite + TiC
Several iron-cobalt alloys were prepared and their compositions are given in
TABLE 3. These cast alloys
were processed into rod and wire, and the measured and calculated T, for the
rods is listed. Averages of cooling and
heating T, measurements were used since no irreversible hysteresis effect was
observed during heating and cooling.
5 As shown in
TABLE 3, the agreement between calculated T. and the measured T, was
acceptable.
The measured T, were performed by inserting rods into a furnace and the T,
temperature was measured
during heating. A thermocouple was attached midway along the length. The torus
technique involves winding a
torus with the sample material.
10 TABLE 3.
Alloy Nominal Composition (% by weight, balance T, (EC) T, (EC) T,
(EC)
Designat being Fe) (torus (rod,
(calculated)
ion technique)
uncorrected)
Co C Mn Si
FM1 0 0 0 0 768 -- 770
181
CA 02871784 2014-11-18
FM2 0 0.1 0.5 0.5 751 758
FM3 5 0 0 0 818
FM4 5 0.1 0.5 0.5 821 803
FM5 8 0 0 0 842
FM6 8 0.1 0.5 0.5 858 826
FM7 10 0 0 0 863 886 859
FM8 10 0.1 0.5 0.5 874 846
FIG. 182 depicts the Curie temperature (solid horizontal bars) and phase
transformation temperature range
(slashed vertical bars) for several iron alloys. Column 1360 is for FM-2 iron-
cobalt alloy. Column 1362 is for FM-4
iron-cobalt alloy. Column 1364 is for FM-6 iron-cobalt alloy. Column 1366 is
for FM-8 iron-cobalt alloy. Column
1368 is for TC I 410 stainless steel alloy with cobalt. Column 1370 is for TC2
410 stainless steel alloy with cobalt.
Column 1372 is for TC3 410 stainless steel alloy with cobalt. Column 1374 is
for TC4 410 stainless steel alloy with
cobalt. Column 1376 is for TC5 410 stainless steel alloy with cobalt. As shown
in FIG. 182, the iron-cobalt alloys
(FM-2, FM-4, FM-6, FM-8) had large phase transformation temperature ranges
that overlap with the Curie
temperature. The 410 stainless steel alloys with cobalt (TC1, TC2, TC3, TC4,
TC5) had small phase transformation
temperature ranges. The phase transformation temperature ranges for TC I, TC2,
and TC3 were above the Curie
temperature. The phase transformation temperature range for TC4 was below the
Curie temperature. Thus, a
temperature limited heater using TC4 may self-limit at a temperature below the
Curie temperature of the TC4.
FIGS. 183-186 depict the effects of alloy addition to iron-cobalt alloys.
FIGS. 183 and 184 depict the
effects of carbon addition to an iron-cobalt alloy. FIGS. 185 and 186 depict
the effects of titanium addition to an
iron-cobalt alloy.
FIG. 183 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-cobalt alloy with 5.63% by weight cobalt and 0.4% by
weight manganese. Curve 1378
depicts weight percentage of the ferrite phase. Curve 1380 depicts weight
percentage of the austenite phase. The
arrow points to the Curie temperature of the alloy. As shown in FIG. 183, the
phase transformation was close to the
Curie temperature but did not overlap with the Curie temperature for this
alloy.
FIG. 184 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by
weight manganese, and 0.01% carbon.
Curve 1382 depicts weight percentage of the ferrite phase. Curve 1384 depicts
weight percentage of the austenite
phase. The arrow points to the Curie temperature of the alloy. As shown in
FIGS. 183 and 184, the phase
transformation broadened with the addition of carbon to the alloy with the
onset of the phase transformation shifting
to a lower temperature. Thus, carbon may be added to an iron alloy to lower
the onset temperature and broaden the
temperature range of the phase transformation.
FIG. 185 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature fir an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by
weight manganese, and 0.085% carbon.
Curve 1386 depicts weight percentage of the ferrite phase. Curve 1388 depicts
weight percentage of the austenite
phase. The arrow points to the Curie temperature of the alloy. As shown in
FIG. 185, the phase transformation
overlapped with the Curie temperature.
182
CA 02871784 2014-11-18
FIG. 186 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by
weight manganese, 0.085% carbon, and
0.4% titanium. Curve 1390 depicts weight percentage of the ferrite phase.
Curve 1392 depicts weight percentage of
the austenite phase. The arrow points to the Curie temperature of the alloy.
As shown in FIGS. 185 and 186, the
phase transformation narrowed with the addition of titanium to the alloy with
the onset of the phase transformation
shifting to a higher temperature. Thus, titanium may be added to an iron alloy
to raise the onset temperature and
narrow the temperature range of the phase transformation.
FIG. 187 depicts experimental calculations of weight percentages of ferrite
and austenite phases versus
temperature for 410 stainless steel type alloy (12% by weight chromium, 0.1%
by weight carbon, 0.5% by weight
manganese, 0.5% by weight silicon, with the balance being iron). Curve 1394
depicts weight percentage of the
ferrite phase. Curve 1396 depicts weight percentage of the austenite phase.
The arrow points to the Curie
temperature of the alloy. As shown in FIG. 187, the phase transformation
broadened without chromium in the alloy
and the phase transformation overlaps with the Curie temperature for this
alloy.
Calculations for the Curie temperature and the phase transformation behavior
were done for various
mixtures of cobalt, carbon, manganese, silicon, vanadium, and titanium using
the computational thermodynamic
software (ThermoCalc and JmatPro) to predict the effect of additional elements
on Curie Temperature (TO for
selected compositions and the temperature (A1) at which ferrite transforms to
paramagnetic austenite. An
equilibrium calculation temperature of 700 C was used in all calculations. As
shown in TABLE 4, as the weight
percentage of cobalt in the composition increased, Tc and A1 decreased. As
shown in TABLE 4, addition of
vanadium and/or titanium increased AI. The addition of vanadium may allow
increased amounts of chromium to be
used in Curie heaters.
TABLE 4
Composition (% by weight, balance being Fe) Calculation Results
Co Cr C Mn Si V Ti T, (EC) A1 (EC)
0 12 0.1 0.5 0.5 0 0 723 814
2 12 0.1 0.5 0.5 0 0 739 800
4 12 0.1 0.5 0.5 0 0 754 788
6 12 0.1 0.5 0.5 0 0 769 780
8 12 0.1 0.5 0.5 0 0 783 773
10 12 0.1 0.5 0.5 0 0 797 766
_
0 12 0.1 0.5 0.5 1 0 726
2 12 0.1 0.5 0.5 1 0 741
4 12 0.1 0.5 0.5 1 0 756
6 12 0.1 0.5 0.5 1 0 770
-
8 12 0.1 0.5 0.5 1 0 784 794
10 12 0.1 0.5 0.5 1 0 797
0 12 0.1 0.5 0.5 2 0 726
..
2 12 0.1 0.5 0.5 2 0 742
183
CA 02871784 2014-11-18
Composition (% by weight, balance being Fe) Calculation Results
Co Cr C Mn Si V Ti T. (EC) A1 (EC)
6 12 0.1 0.5 0.5 2 0 772
_
8 12 0.1 0.5 0.5 2 0 785 817
12 0.1 0.5 0.5 2 0 797
0 12 0.1 0.5 0.5 0 0.5 718 863
2 12 0.1 0.5 0.5 0 0.5 733 825
_
4 12 0.1 0.5 0.5 0 0.5 747 803
6 12 0.1 0.5 0.5 0 0.5 761 787
_
8 12 0.1 0.5 0.5 0 0.5 775 775
10 12 0.1 0.5 0.5 0 0.5 788 767
0 12 0.1 0.5 0.5 1 0.5 721
2 12 0.1 0.5 0.5 1 0.5 736
4 12 0.1 , 0.5 0.5 1 0.5 , 750
6 12 0.1 0.5 0.5 1 0.5 763
8 12 0.1 0.5 0.5 1 0.5 776
10 12 0.1 0.5 0.5 1 0.5 788 ,
0 12 0.1 0.5 0.5 2 , 0.5 725
2 12 0.1 0.5 0.5 2 , 0.5 738
4 , 12 0.1 0.5 0.5 2 0.5 752
6 12 0.1 0.5 0.5 2 0.5 764
8 12 0.1 0.5 0.5 2 0.5 777
10 12 0.1 0.5 0.5 2 0.5 788
0 12 0.1 0.5 0.5 0 1 712 >1000
2 12 0.1 0.5 0.5 0 1 727 877
4 12 0.1 0.5 0.5 0 1 741 836
6 12 0.1 0.5 0.5 0 , 1 755 810
8 12 0.1 0.5 0.5 0 1 768 794
10 12 0.1 0.5 0.5 0 1 781 780
0 12 0.1 0.5 0.5 1 1 715
2 12 0.1 0.5 0.5 1 1 730
4 12 0.1 0.5 0.5 1 , 1 743
6 12 0.1 0.5 0.5 1 1 757
_
184
CA 02871784 2014-11-18
Composition (% by weight, balance being Fe) Calculation Results
Co Cr C Mn Si V Ti T. (EC) Al (EC)
8 12 0.1 0.5 0.5 I 1 770 821
12 0.1 0.5 0.5 1 1 782
0 12 0.1 0.5 0.5 2 1 718
2 12 0.1 0.5 0.5 2 1 732
4 12 0.1 0.5 0.5 2 1 745
6 12 0.1 0.5 0.5 2 1 758
8 12 0.1 0.5 0.5 2 1 770 873
10 12 0.1 0.5 0.5 2 I 782
0 12 0.1 0.3 0.5 0 0 727 826
2 12 0.1 0.3 0.5 0 0 742 810
4 12 0.1 0.3 0.5 0 0 758 800
6 12 0.1 0.3 0.5 0 0 772 791
8 12 0.1 0.3 0.5 0 0 786 784
10 12 0.1 0.3 0.5 0 0 800 777
0 12 0.1 0.3 0.5 1 0 730
2 12 0.1 0.3 0.5 I 0 745
4 12 0.1 0.3 0.5 1 0 760
6 12 0.1 0.3 0.5 1 0 774
8 12 0.1 0.3 0.5 1 0 787
10 12 0.1 0.3 0.5 I 0 801
0 12 0.1 0.3 0.5 2 0 730
2 12 0.1 0.3 0.5 2 0 746
4 12 0.1 0.3 0.5 2 0 762
6 12 0.1 0.3 0.5 2 0 775
8 , 12 0.1 0.3 0.5 2 0 788 .
10 12 0.1 0.3 0.5 2 0 801
0 12 0.1 0.3 0.5 0 0.5 722
2 12 0.1 0.3 0.5 0 0.5 737
4 12 0.1 0.3 0.5 0 0.5 751
6 12 0.1 0.3 0.5 0 0.5 765 ,
8 12 0.1 0.3 0.5 0 0.5 779
10 12 0.1 0.3 0.5 0 0.5 792
185
CA 02871784 2014-11-18
Composition (% by weight, balance being Fe) Calculation Results
Co Cr C Mn Si V Ti T, (EC) A1 (EC)
_
0 12 0.1 0.3 0.5 1 0.5 725
2 , 12 0.1 0.3 0.5 1 0.5 740
4 12 0.1 0.3 0.5 1 0.5 753
6 12 0.1 0.3 0.5 1 0.5 767
_ 8 12 0.1 0.3 0.5 1 0.5 780
12 0.1 0.3 0.5 1 0.5 792
0 12 0.1 0.3 0.5 2 0.5 728
2 12 0.1 0.3 0.5 7 0.5 742
4 12 0.1 0.3 0.5 2 0.5 755
6 12 0.1 0.3 0.5 2 0.5 768
8 12 0.1 0.3 0.5 2 0.5 780
10 12 0.1 0.3 0.5 2 0.5 792
. ,
0 12 0.1 0.3 0.5 0 1 715
. 2 12 0.1 0.3 0.5 0 I 730
4 12 0.1 0.3 0.5 0 1 745
6 12 0.1 0.3 0.5 0 1 759
8 12 0.1 0.3 0.5 0 1 772
10 12 0.1 0.3 0.5 0 1 785
0 12 0.1 0.3 0.5 1 I 719
2 12 0.1 0.3 0.5 1 1 733
4 12 0.1 0.3 0.5 I 1 747
6 12 0.1 0.3 0.5 1 I 760
8 12 0.1 0.3 0.5 1 1 773 834
. 10 12 0.1 0.3 0.5 1 1 786
0 12 0.1 0.3 0.5 2 1 722
. 2 12 0.1 0.3 0.5 2 1 736
4 12 0.1 0.3 0.5 2 1 749
6 12 0.1 0.3 0.5 2 1 762
8 12 0.1 0.3 0.5 2 1 774 886
10 12 0.1 0.3 0.5 2 I 786
7.5 12.25 0.1 0.3 0.5 0 0 781 785
. 8.0 12.25 0.1 0.3 0.5 0 0 785 783
186
CA 02871784 2014-11-18
Composition (% by weight, balance being Fe) Calculation Results
Co Cr C Mn Si V Ti Tc (EC) A1 (EC)
8.5 . 12.25 0.1 0.3 0.5 0 0 788 781
9.0 12.25 0.1 0.3 0.5 0 0 792 779
9.5 12.25 0.1 0.3 0.5 0 0 795 778
10.0 12.25 0.1 0.3 0.5 0 0 798 776
6.0 12.25 0.1 0.5 0.5 0 0 767 780
6.5 12.25 0.1 0.5 0.5 0 0 771 778
7.0 12.25 0.1 0.5 0.5 0 0 774 776
7.5 12.25 0.1 0.5 0.5 0 0 778 774
7.5 12.25 0.1 0.3 0.5 1 0 782 812
8.0 12.25 0.1 0.3 0.5 1 0 786 809
8.5 12.25 , 0.1 0.3 0.5 1 0 789 806
9.0 12.25 0.1 0.3 0.5 1 0 792 804
9.5 12.25 0.1 0.3 0.5 1 0 795 801
10.0 12.25 0.1 0.3 0.5 1 0 799 799
7.5 12.25 0.1 0.5 0.5 , 1 0 779 801
8.0 12.25 0.1 0.5 0.5 1 0 782 799
8.5 12.25 0.1 0.5 0.5 1 0 785 796
9.0 12.25 0.1 0.5 0.5 1 0 788 793
9.5 12.25 0.1 0.5 0.5 1 0 792 791
10.0 12.25 0.1 0.5 0.5 1 0 795 788
7.5 12.25 0.1 0.3 0.5 0 0.5 774 788
8.0 12.25 0.1 0.3 0.5 0 0.5 777 785
8.5 12.25 0.1 0.3 0.5 0 0.5 781 782
9.0 12.25 0.1 0.3 0.5 0 0.5 784 780
7.5 12.25 0.1 0.5 0.5 0 0.5 770 777
8.0 12.25 0.1 0.5 0.5 0 0.5 774 774
8.5 12.25 0.1 0.5 0.5 0 0.5 777 771
7.5 12.25 0.1 0.3 0.5 1 0.5 775 823
8.0 12.25 0.1 0.3 0.5 1 0.5 778 819
8.5 12.25 0.1 0.3 0.5 1 0.5 782 814
9.0 12.25 0.1 0.3 0.5 1 0.5 785 810
9.5 12.25 0.1 0.3 0.5 1 0.5 788 807
187
CA 02871784 2014-11-18
Composition (% by weight, balance being Fe) Calculation Results
Co Cr C Mn Si V Ti I', (EC) Ai (EC)
10.0 12.25 0.1 0.3 0.5 1 0.5 791 803
10.5 12.25 0.1 0.3 0.5 1 0.5 794 800
11.0 12.25 0.1 0.3 0.5 1 0.5 797 797
7.5 12.25 0.1 0.5 0.5 1 0.5 771 811
..
8.0 12.25 0.1 0.5 0.5 1 0.5 775 807
8.5 12.25 0.1 0.5 0.5 1 0.5 778 803
9.0 12.25 0.1 0.5 0.5 1 , 0.5 781 799
9.5 12.25 0.1 0.5 0.5 1 0.5 784 796
10.0 12.25 0.1 0.5 0.5 1 0.5 787 792
10.5 12.25 0.1 0.5 0.5 1 0.5 790 789
Several iron-chromium alloys were prepared and their compositions are given in
TABLE 5. These cast
alloys were processed into rod and torus, and the calculated and measured 'I',
for the torus and rods is listed.
TABLE 5
Alloy Actual Composition (% by weight, balance Fe) Tc Tc Tc
Tc A1
Designa (EC) (EC) (EC)
(EC) (EC)
tion Co Cr C Mn Si V Ti (torus) (rod, (calori (calcul (calcul
uncorr metry) ated) ated)
ected)
. .
TC1b 0.02 13.2 0.08 0.45 0.69 0 0.01 692 --
-- 717 819
TC2 2.44 12.3 0.10 0.48 0.47 0 0.01 --
745 -- 742 793
TC3 4.81 12.3 0.10 0.48 0.46 0 0.01 --
758 -- 761 783
TC4 9.75 12.2 0.07 0.49 0.47 0 0.01 759/
770/ -- 793 765
682* 684*
TC5 9.80 12.2 0.10 0.48 0.46 1.02 0.01 --
784/ -- 795 790
690*
TC6 7.32 12.3 0.12 0.29 0.46 0.89 0.46 754 -
- 752 775 813
. .
TC7 7.46 12.1 0.11 0.27 0.46 0.92 0 747 --
757 785 811
_
TC8 7.49 12.1 0.11 0.28 0.45 0 0 761 --
774 784 786
* Two values represent Tc during heating and Tc during subsequent cooling.
Modeling of Alloy Phase Behavior
Modeling of phase behavior for different improved alloy compositions to
determine compositions that
contain increased amounts of phases that contribute positively to physical
properties was performed. Compositions
such as Cu, Z, M(C,N), M2(C,N), and M23C6, and may minimize the amount of
phases that are embritting phases
such as G, sigma, laves, and chi. There may be other reasons to include
certain components. For example, silicon, is
typically included in stainless steel alloys to improve processing properties,
and nickel and chromium are typically
included in the alloys to impart corrosion resistance. When two components may
be included to accomplish the
188
CA 02871784 2014-11-18
same result, then the less expensive component may be beneficially included.
For example, to the extent manganese
may be substituted for nickel without sacrificing performance, such a
substitution may reduce the cost of the alloy at
current component prices.
The effect of total phase content of the alloys similar to those described
above has been found to be
approximated by the equation:
(10) o=1.0235 (TPC) + 5.5603
Where or is the creep rupture strength for one thousand hours at 800 C in
(kilo-pound per square inch (ksi)
and TPC is the total phase content calculated for the composition. This
estimate was further improved by only
including in the TPC term the amount of Cu phase, Z phase, M(C,N) phase,
M2(C,N) phase, and M23C6 phase (the
"desirable phases"), and calculating the constants on this basis. Another
improvement to this estimate may be to use
only the difference between the desirable phases present at the annealing
temperature and at 800 C. Thus, the
components that do not go into solution in the annealing process were not
considered because they do not add
significantly to the strength of the alloys at elevated temperatures. For
example, the difference between the amount
of Cu phase, Z phase, M(C,N) phase, M2(C,N) phase, and M23C6 phase present
based on equilibrium calculations at
annealing temperatures less the amount calculated to be present at 800 C may
be about 1% by weight of the alloy,
or it could be about 1.5% by weight of the alloy or about 2% by weight of the
alloy, to result in an alloy with good
high temperature strength. Further, the annealing temperature may be about
1200 C, or it may be about 1250 C, or
it may be about 1300 C.
The improved alloys of the present invention may be further understood by
modeling the addition, or
reduction, of different metals to determine the effect of changing amounts of
that metal on the phase content of the
alloy. For example, with a starting composition by weight of: 20% Cr, 3% Cu,
4% Mn, 0.3% Mo, 0.8% Nb, 12.5%
Ni, 0.5% Si, 1%W, 0.1%C and 0.25% N, modeling with varying amounts of Cr
results in included phases of M23C6,
M(C,N), M2(C,N), Z, Cu, chi, laves, G, and sigma at 800 C, according to FIG.
188. The amount of these phases
plotted in each of FIGS. 188-198 is the calculated amount of these phases at
800 C. In FIGS 188-198, curve 1398
refers to M23C6, curve 1400 refers to M2(C,N) phase, curve 1402 refers to Z
phase, curve 1404 refers to Cu phase,
curve 1406 refers to sigma phase, curve 1408 refers to chi phase, curve 1410
refers to G phase, curve 1412 refers to
laves phase, and curve 1414 refers to M(C,N) phase.
FIG. 188 depicts the weight percentages of phases verus weigh percentage of
chromium (Cr) in the alloy.
As shown, the weight percentages of phases 1398, 1400, 1402, and 1404 remained
relatively constant from about
20% by weight to about 30% by weight of chromium, while sigma phase 1406
increased linearly above a chromium
content of about 20.5% by weight. Thus, from the modeling, a chromium content
between about 20% by weight and
about 20.5% by weight of the alloy may be favorable.
FIG. 189 depicts weight percentages of phases verus the weight percentage of
silicon (Si) in the alloy. As
shown in IG. 189, varying the silicon content of the alloy resulted in sigma
phase 1406 appearing at levels above
about 1.2% by weight silicon and chi phase 1408 appearing above a content of
about 1.4% by weight silicon. G
phase 1410 appeared above about 1.6% by weight silicon and increased as the
weight percent of silicon increased.
With increasing weight percentages of silicon, phases 1398, 1400, and 1402,
remained relatively constant and a
slight increase in Cu phase 1404 was predicted. The appearance of sigma phase
1406, chi phase 1408 and G phase
1410 indicates that a silicon content below about 1.2% by weight in this alloy
may be favorable.
FIG. 190 depicts weight percentage of phases formed verus weight percentage of
tungsten (W) in the alloy.
As shown in FIG. 190, varying the weight percentage of tungsten (W) in the
alloy resulted in sigma phase 1406
appearing at about 1.4% by weight tungsten. Laves phase 1412 appeared at about
1.5% by weight tungsten and
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CA 02871784 2014-11-18
increased with increasing weight percentage of tungsten. Thus, the model
predicts a tungsten content in this alloy of
below about 1.3% by weight may be favorable.
FIG. 191 depicts weight percentage of phases formed versue the weight
percentage of niobium (Nb) in the
alloy. As shown in FIG. 191, modeling predicted that weight percentage of Z
phase 1402 increased in a linear
fashion as the weight percentage of niobium (Nb) increased in the alloy until
the niobium content of the alloy
reached about 1.55% by weight. As the niobium content increased from about
0.1% by weight to about 1.4% by
weight, M2(C,N) phase 1400 decreased fairly linearly. The decrease in M2(C,N)
phase 1400 was compensated for
by the increase in Z phase 1402, and Cu phase 1404 and M23C6 phase 1398. Above
about 1.5% by weight niobium
in the alloy, sigma phase 1406 increased rapidly, Z phase 1402 decreased,
M23C6 phase 1398 decreased, and M(C,N)
phase 1414 appeared. Thus, the niobium content in the alloy of at most 1.5% by
weight may maximize the weight
percent of phases 1398, 1400, 1402, and 1404 and avoid minimizing the weight
percent of sigma phase 1406 formed
in the alloy. In order to make the alloy hot-workable, it was found that at
least about 0.5% by weight of niobium was
desirable. Thus, in some embodiments, the alloy contains from about 0.5% by
weight to about 1.5% by weight, or
from about 0.8% by weight to about I% by weight niobium.
FIG. 192 depicts weight perctanges of phases formed verus weight percentage of
carbon (C). As shown in
FIG. 192, weight percentage of sigma phase 1406 was predicted to decrease as
the weight percentage of carbon in
the alloy increased from about 0 to about 0.06. The weight percentage of M23C6
phase 1398 was predicted to
increase linearly as the weight percentage of carbon in the alloy increased to
at most 0.5. M2(C,N) phase 1400, Z
phase 1402, and Cu phase 1404 was predicted to remain relatively constant as
the weight percentage of carbon
increased in the alloy. Since, sigma phase 1406 decreased after about 0.06% by
weight carbon, a carbon content of
about 0.06% by weight to about 0.2% weight in the alloy may be beneficial.
FIG. 193 depicts weight percentage of phases formed verus weight percentage of
nitrogen (N). As shown
in FIG. 193, the content of nitrogen in the alloy increased from about 0% by
weight to about 0.15% by weight, a
content of sigma phase 1406 decreased from about 7% by weight to about 0% by
weight, a content of M(C,N) phase
1414 decreased from about 1% by weight to about 0% by weight, a content of
M23C6 phase 1398 increased from
about 0% by weight to about 1.9% by weight, and a content of Z phase 1402
increased from about 0% by weight to
about 1.4% by weight. Above a nitrogen content of 0.15% by weight in the
alloy, M2(C,N) phase 1400 appeared and
increaseed with as the content of nitrogen in the alloy increases. Thus, a
nitrogen content in a range of about 0.15%
to about 0.5% by weight in the alloy may be beneficial.
FIG. 194 depicts weight percentage of phases formed verus weight percentage of
titanium (Ti). As shown
in FIG. 194, varying the weight percentage of titanium from 0.19 to about 1
may contribute to an increase in a
weight percentage of sigma phase 1406 from about 0 to about 7.5 in the alloy.
Thus, a titanium content of below
about 0.2% by weight in the alloy may be desirable. As shown, as the content
of Ti increased from about 0% by
weight to about 0.2% by weight, an increase in the weight percentage of M(C,N)
phase 1414 occurred, a decrease in
the weight percentage of M2(C,N) phase 1400 occurred, and a decrease in the
weight percentage Z phase 1402
occurred. The decreases in the amount of M2(C,N) phase 1400 and Z phase 1402
appear to offset the increase in the
weight percent of M(C,N) phase 1414. Thus, inclusion of Ti in the alloy may be
for purposes other than for
increasing the amount of phases that improve properties of the alloy.
FIG. 195 depicts weight percentage of phases formed versus weight percentage
of copper (Cu). As shown
in In FIG. 195, weight percentages of M23C6 phase 1398, M2(C,N) phase 1400,
and Z phase 1402 did not vary
significantly as the weight percent of copper in the alloy increased. When the
content of copper in the alloy
increases above about 2.5% by weight, Cu phase 1404 increased significantly.
Thus, in some embodiments, it is
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CA 02871784 2014-11-18
desirable to have more than about 3% by weight copper in the alloy. In some
embodiments, about 10% by weight of
copper in the alloy is beneficial.
FIG. 196 depicts weight percentage of phases formed verus weight percentage of
manganese (Mn). As
shown in FIG. 196, varying the content of manganese in the alloy did not
greatly affect the weight percentage of
beneficial phases M23C6 phase 1398, M2(C,N) phase 1400, Z phase 1402, and Cu
phase 1404 in the alloy. The
amount of manganese may therefore be varied in order to reduce cost, or for
other reasons, without significantly
effecting the high temperature properties of the alloy, with an acceptable
range of manganese content of the alloy
being from about 2% by weight to about 10% by weight.
FIG. 197 depicts weight percentage of phases formed verus weight percentage of
nickel (Ni). As shown in
FIG. 197, as the nickel content of the alloy increased above about 8.4% by
weight, a decrease in sigma phase 1406
was observed. As the Ni content of the alloy was increased from about 8% by
weight to about 17% by weight, Cu
phase 1404 decreased almost linearly until it disappeared at about 17% by
weight and a small increase in the weight
percentage of M2(C,N) phase 1400 was predicted. From the model, a content of
nickel of about 10% by weight to
about 15% by weight in the alloy, or in other embodiments, a nickel content of
about 12% by weight to about 13%
by weight in the alloy may avoid the formation of sigma phase 1406, while
improvements in corrosion properties
offset any detrimental effect of less Cu phase 1404.
FIG. 198 depicts weight percentage of phases formed verus weight percentage of
molybdenum (Mo). As
shown in FIG. 198, the weight percentage of beneficial phases M23C6 phase
1398, M2(C,N) phase 1400, Z phase
1402, and Cu phase 1404 remained relatively constant as the weight percentage
of molybdenum in the alloy was
varied. As Mo content of the alloy exceeded about 0.65% by weight, the weight
percentages of sigma phase 1406
and chi phase 1408 in the alloy increased significantly with no significant
changes in the other phases. The content
of molybdenum in the alloy, in some embodiments, may therefore be limited to
at most about 0.5% by weight.
Alloy Examples
Alloys A through N were prepared according to TABLE 6. Measured compositions
are included in the
table when such measurements are available. The total phase content of the
alloys are calculated for the composition
listed.
TABLE 6
% by weight
Alloy 800
Cr Cu Mn Mo Nb Ni Si W C N2 Ti
Total
Phase
Target 20 4 0.3 0.8 12.5 0.5 -- 0.09 0.25 --
A
Actual"
19 -- 4.2 0.3 0.8 12.5 0.5 -- 0.09 0.24 -- 3.35'
Target 20 3 4
0.3 0.8 13 0.5 I 0.09 0.25 --
Actual-I"
20 3 4 0.3 0.77 13 0.5 1 0.09 0.26 -- 4.40'
Actual-2" 20.35 2.94 4.09 0.28 0.76 12.52 0.44 1.03 0.09 0.23 --
Actual-3"'" 18.78 2.94 2.85 029 _ 0.65 12.75
0.39 1.03 _1- 0.10 1 0.23 0.004
Target
20 4.5 4 0.3 0.8 12.5 0.5 1 0.15 0.25 -- 7.15
C Actual-1"
18.74 4.37 3.68 0.29 0.77 13.00 0.43 1.18 0.11 0.17 0.002 5.45
Actual-2 ' 20.48 4.75 4.13 0.30 0.07 12.81 0.52 1.18 0.17 0.14 0.01 6.23
D Target 20 4.5 4 0.3 0 12.5 0.5 1 0.2 0.5 0
10
Target 20 4 4 0.5 0.8 12.5 0.5 1 0.1
0.3 -- 6.2
Actual 18.84 4.34 3.65 0.29 0.75 12.93 0.43
1.21 _ 0.09 0.2 0.002 5.3
Target 20 3 1 0.3
0.77 13 0.5 1 0.09 0.26 4.7
Actual"
18.97 2.88 0.92 0.29 0.74 13.25 0.43 1.17 0.05 0.12 <0.001 2.45
191
CA 02871784 2014-11-18
c/o by weight
Alloy 800
Cr Cu Mn Mo Nb Ni Si W C N2 Ti
Total
Phase
Target 20 4.5 4 0.3 0.8 7 0.5 1 0.2 0.5
Actual' 20.08
4.36 4 0.3 0.81 7.01 0.5 1.04 0.24 0.31 0.008 9.60
Target 21 3 3 0.3 0.80 7 1 2 0.1 0.4
Actual' 21.1 2.95
3.01 0.31 0.82 6.98 0.51 2.06 0.13 0.32 <0.001 13.46f
Target 21 3 8 0.3 0.80 7 0.5 1 0.1 0.5
7.1
Actual' 21.31
2.94 7.95 0.31 0.83 7.02 0.52 1.05 0.13 0.37 0.003 9.45
Target 20 4 2 0.5 1.00 12.5
1 1 0.20 0.50 9.8
Actual' 19.93 3.85 2.13 0.5 0.99 12.11 1.08 1.01
0.23 0.29 0.022 8.95
K _Target 20 3 4 0.3 0.77 13 0.5 1 0.09 0.26
Actual' 18.94
2.96 4.01 0.31 0.81 13.05 0.52 1.03 0.12 0.35 0.018 5.62
Target 20 3 4 0.3 0.10 13
0.5 1 0.09 0.26
Actualb 20.06
2.96 3.95 0.3 0.12 12.93 0.59 1.03 0.11 0.25 0.005 4.28
MTarget 20 3 4
0.3 0.50 13 0.5 1 0.09 0.26
-
Actualb 20.11
2.93 3.98 0.3 0.51 12.94 0.5 1.03 0.12 0.13 <0.001 2.76
N _ Target 20 3.4 4 1 0.80 12.5 0.5 2 0.1
0.3 8.85g
aCalculated using actual composition; bNonconsumable-arc melted; cRemelted by
element compensation; dContains
1.7% sigma phase and 1.55% laves phase; 'Induction melted; 'Contains 3.9%
sigma phase and 1.7% chi phase;
gIncludes 1.7% sigma and 1.55% laves phases.
Hot working with Niobium Example
To determine the capability for alloys to be hot worked, samples of alloys C,
D, E, F, K and L in TABLE 6
were prepared by arc-melting one pound samples into ingots of about 25.4
millimeter x 24.4 millimeter x 101.6
millimeter (1 inch x 1 inch x 4 inch). After cutting hot-tops and removing
some shrinkage underneath, each sample
was homogenized at 1200 C for one hour, and then hot-rolled to a thickness of
about 12.7 millimeter (0.5 inch) at
1200 C with intermediate heat. The samples were then cold rolled to a 6.34
millimeter (0.25 inch) thick plate and
vacuum annealed at 1200 C for one hour. The compositions of the samples are
included in TABLE 7 below, with
the balance of the compositions being iron.
When alloy D was hot rolled, it cracked and the rolling to 12.7 millimeter
(0.5 inch) thickness could not be
accomplished. Alloy L could be hot-rolled, but developed cracks from the edge
of the samples progressing toward
the center of the sample, and would not be a useful material after such hot
rolling. The other samples were
processed using the above described procedure without any problems, resulting
in 6.35 millimeter (0.25 inch) plates
that were free of cracks. It has been found that even 0.07% by weight niboium
in the alloy composition may
significantly reduce the tendency of the alloy to develop cracks during hot
working, and about 0.5% by weight to
about 1.2% by weight niobium can be incorporated in wrought alloys to improve
properties such as hot workability.
High Temperature Heat Treating Example
Samples of alloys A and B from TABLE 6 were processed by two different
methods. Process A included a
heat treating and an annealing step which were at 1200 C. Process B included
a heat treating and an annealing step
which were at 1250 C. With the higher heat treating and annealing
temperatures, measurable improvements in
yield strength and ultimate tensile strength were observed for the two alloys
when processed at the higher
temperature.
The process with 1200 C processing was accomplished as follows: sections of
six inch ID by 1.5 inches
thick centrifugally cast pipe were homogenized at 1200 C for one and a half
hours; a section was then hot-rolled at
1200 C to a one inch thickness for alloy A and a three-quarter inch thickness
for alloy B; after cooling to room
temperature, the plates were given a fifteen minute anneal at 1200 C; the
plates were then cold-rolled to a thickness
192
CA 02871784 2014-11-18
of 13.97 millimeter (0.55 inches); the cold-rolled plates were given an anneal
for one hour at 1200 C in air with an
argon blanket; and the plates were then given a final anneal for one hour at
1250 C in air with an argon blanket.
This process is referred to herein as process A.
The process with higher heat treating and annealing temperatures varied from
the above procedure by
homogenization of the cast plates at 1250 C for three hours instead of one
and a half hours; hot rolling was carried
out at 1200 C from a one and a 12.7 millimeter (0.5 inch) thickness to a
19.05 millimeter (0.75 inch) thickness; and
the resulting plate was annealed for fifteen minute at 1200 C followed by
cold-rolling to 13.97 millimeter (0.55
inch) thickness. This process is referred to herein as process B.
FIG. 199 depicts yield strengths and ultimate tensile strengths for different
metals. Data 1416 shows yield
strength and data 1418 shows ultimate tensile strength for alloy A treated by
process A. Data 1420 shows yield
strength and data 1422 shows ultimate tensile strength for alloy B treated by
process B. Data 1424 shows yield
strength and data 1426 shows ultimate tensile strength for 347H stainless
steel. Both ultimate tensile strength and
yield strength were greater for the alloys treated at higher temperatures as
compared to 347H stainless steel. A
considerable improvement over 347H can be seen for alloys A and B. For
example, alloy A and alloy B retained
tensile properties to test temperatures of about 1000 C. For an application
where yield strength of about 20 ksi was
needed, alloy A and alloy B provide the needed yield strength for at least an
additional about 250 C. For a 5 ksi
difference between yield and ultimate tensile strength at test temperatures,
alloy A and alloy B may be used at
temperatures of about 950 C and about 1000 C as opposed to only about 870 C
for 347H.
Samples of Alloy B, treated by process A and by process B were subjected to
stress-rupture tests and the
results are tabulated in TABLE 7. It can be seen from Table 7 that process B,
with a higher annealing temperature,
resulted in about 47% to about 474% improvement in time to rupture.
TABLE 7
Temperature (C) Stress(MPa) Process A life Process B life
Improvement by
(hours) (hours) Process B
800 100 164.2 241.6 47%
850 70 32 151.7
474%
850 55 264.1 500.7 90%
900 42 90.1 140.1 55%
High Temperature Yield After Cold Work and Aging Example
A sample of alloy B, processed by process B, was aged at 750 C for 1000 hours
after being cold worked by
2.5%, 5%, and 10%, and without cold working. After aging, each was tested for
tensile strength and yield strength at
about 750 C. Results are tabulated in TABLE 8. It can be seen from TABLE 8,
that the yield strength increased
significantly as a result of cold work and high temperature aging. The
ultimate tensile strength at about 750 C
decreased only slightly as a result of the high temperature aging and cold
working. The annealed only sample and the
aged only sample were also tested at room temperature for yield strength and
ultimate tensile strength. The yield
strength at room temperature increased from 307 MPa to 318 MPa as a result of
the aging. The ultimate tensile
strength decreased from 720 MPa to 710 MPa as a result of the high temperature
aging.
TABLE 8
Annealed Aged 2.5% Cold Worked 5% Cold Worked 10%
Cold
and aged and aged
Worked and aged
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CA 02871784 2014-11-18
Yield Strength, MPa 170 212 235 290 325
Ultimate Tensile Strength, 372 358 350 360 358
MPa
These characteristics may be compared to competing alloys such as 347H, which
significantly lose high
temperature properties as a result of only, for example, 10% cold work.
Because fabrication of tubulars and heaters
useful in an in situ heat treatment process often require cold work for their
fabrication, improvement of some high
temperature properties, or at least lack of significant loss of high
temperature properties may be a significant
advantage for alloys having these characteristics. It may be particularly
advantageous when these properties are
improved, or at least not significantly decreased, by high temperature aging.
Creep Example
Samples of alloys were subjected to 100 MPa stress at 800 C in a nitrogen
with about 0.1% oxygen test
environment. Each of the samples were first annealed for one hour at 1200 C.
TABLE 9 shows the time to rupture,
elongation at rupture, and total phase content, where the total phase content
is known.
TABLE 9
Alloy Rupture time (hr) Elongation Total Phase comments
(%) Content % at
800
C
B 283 7.6 4.4
B 116 5.6 4.4
B 127 3.9 4.4
10% cold work
B 228 3.1 4.4
10% cold work
B 185 2.3 4.4
Laser weld
C 60 5.3 5.45
C 137 3.6 5.45 Repeated
test
E 165 5.1 5.3
F 24 6.6 2.45
G 178 11.3 9.6
H 183 9.8 13.46 total
7.86 good phases
I 228 12.6 9.45
J 240 19.7 8.95
K 123 14.2 5.62
N 147 7.4 8.85
347H 1.87 92 0.75 As received
347H 2.1 61 0.75 As received
NF709 56 32 Annealed
NF709 30 29.4
NF709 36 26 Cold Strain 10%
NF709 82 30.6 Cold Strain 10%
194
CA 02871784 2014-11-18
Alloy Rupture time (hr) Elongation Total Phase
comments
( /0) Content '5/0 at 800
C
NF709 700 16.2 Cold
Strain 15%
NF709 643 11.4 Cold
Strain 20%
NF709 1084 6 Cold
Strain 20%
NF709 754 37.6 As
received
A sample of the improved alloy B was rolled processed and rolled into a tube,
and the seam welded, to form
a 31.75 millimert (1.25 inch) OD pipe. The pipe was then cut and welded back
together in order to test the strength
of the weld. The filler metal was ERNiCrMo-3, and the weld was completed with
argon shielding gas and three
passes with a preheat minimum temperature of about 50 C and an interpass
maximum temperature of about 350 C.
Creep failure was tested for the segment of welded pipe at 44.8 MPa and 900
C. A rupture time of 41 hours was
measured with failure at a strain of 5.5%. This demonstrated that the weld,
including the heat affected zone around
the weld, was not significantly weaker than the base alloy.
Metal Sullidation Example
FIG. 200 depicts projected corrosion rates (metal loss per year) over a one-
year period for several metals in
a sulfidation atmosphere. The metals were exposed to a gaseous mixture
containing about 1% by volume carbon
monoxide sulfide (COS), about 32% by volume carbon monoxide (CO) and about 67%
volume CO2 at 538 C (1000
F), at 649 C (1200 C), at 760 C (1400 F), and at 871 C (about 1600 F)
for 384 hours. The resulting data was
extrapolated to a one-year time period. The experimental conditions simulates
in-situ sub-surface formation
sulfidation conditions of 10% H2 by volume, 10% H2S by volume and 25% H20 by
volume at 870 C. Curve 1428
depicts 625 stainless steel. Curve 1430 depicts CF8C+ stainless steel. Curve
1432 depicts data for 410 stainless
steel. Curve 1434 depicts 20 25 Nb stainless steel. Curve 1436 depicts 253 MA
stainless steel. Curve 1438 depicts
347H stainless steel. Curve 1440 depicts 446 stainless steel. 410 stainless
steel exhibits a decrease in corrosion at
temperatures between about 500 C and about 650 C.
In some embodiments, cobalt is added to 410 stainless steel to decrease the
rate of corrosion at elevated
temperatures (for example, temperatures greater than 1200 F) relative to
untreated 410 stainless steel. Addition of
cobalt to 410 stainless steel may enhance the strength of the stainless steel
at high temperatures (for example,
temperatures greater than 1200 F, greater than 1400 F, greater than 1500 F,
or greater than 1600 F) and/or
change the magnetic characteristics of the metal. FIG. 201 depicts projected
corrosion rates (metal loss per year) for
410 stainless steel and 410 stainless steel containing various amounts of
cobalt in a sulfidation atmosphere. The
metals were exposed to the same conditions as the metals in FIG. 201. Bars
1442 depicts data for 410 stainless steel.
Bar 1444 depicts data for 410 stainless steel with 2.5% cobalt by weight. Bar
1446 depicts data for 410 stainless
steel with 5% cobalt by weight. Bar 1448 depicts data for 410 stainless steel
with 10% cobalt by weight. As shown
in FIG. 201, as the amount of cobalt in the 410 stainless steel increases, the
corrosion rate in a sulfidation
atmosphere decreases relative to non-cobalt containing 410 stainless steel in
a temperature range of about 800 C to
about 880 C.
Varying Heater Output Simulation
A STARS simulation determined heating properties using temperature limited
heaters with varying power
outputs. FIG. 202 depicts an example of richness of an oil shale formation
(gal/ton) versus depth (ft). Upper
portions of the formation (above about 1210 feet) tend to have a leaner
richness, lower water-filled porosity, and/or
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CA 02871784 2014-11-18
less dawsonite than deeper portions of the formation. For the simulation, a
heater similar to the heater depicted in
FIG. 45 was used. Portion 550 had a length of 368 feet above the dashed line
shown in FIG. 202 and portion 548
had a length of 587 feet below the dashed line.
In the first example, the temperature limited heater had constant thermal
properties along the entire length
of the heater. The heater included a 14.34 millimter (0.565 inch) diameter
copper core with a carbon steel conductor
(Curie temperature of 1418 F, pure iron with outside diameter of 20.955
millimeter (0.825 inch)) surrounding the
copper core. The outer conductor was 347H stainless steel surrounding the
carbon steel conductor with an outside
diameter of 31.75 millimeter (1.2 inch). The resistance per foot (mQ/ft)
versus temperature ( F) profile of the heater
is shown in FIG. 203. FIG. 204 depicts average temperature in the formation (
F) versus time (days) as determined
by the simulation for the first example. Curve 1450 depicts average
temperature versus time for the top portion of
the formation. Curve 1452 depicts average temperature versus time for the
entire formation. Curve 1454 depicts
average temperature versus time for the bottom portion of the formation. As
shown, the average temperature in the
bottom portion of the formation lagged behind the average temperature in the
top portion of the formation and the
entire formation. The top portion of the formation reached an average
temperature of 340 C (644 F) in 1584 days.
The bottom portion of the formation reached an average temperature of 340 C
(644 F) in 1922 days. Thus, the
bottom portion lagged behind the top portion by almost a year to reach an
average temperature near a pyrolysis
temperature.
In the second example, portion 550 of the temperature limited heater had the
same properties used in the
first example. Portion 548 of the heater was altered to have a Curie
temperature of 843 C (1550 F) by the addition
of cobalt to the iron conductor. FIG. 205 depicts resistance per foot (m0./ft)
versus temperature ( F) for the second
heater example. Curve 1456 depicts the resistance profile for the top portion
(portion 550). Curve 1458 depicts the
resistance profile for the bottom portion (portion 548). FIG. 206 depicts
average temperature in the formation ( F)
versus time (days) as determined by the simulation for the second example.
Curve 1460 depicts average temperature
versus time for the top portion of the formation. Curve 1462 depicts average
temperature versus time for the entire
formation. Curve 1464 depicts average temperature versus time for the bottom
portion of the formation. As shown,
the average temperature in the bottom portion of the formation lagged behind
the average temperature in the top
portion of the formation and the entire formation. The top portion of the
formation reached an average temperature
of 340 C (644 F) in 1574 days. The bottom portion of the formation reached
an average temperature of 340 C
(644 F) in 1701 days. Thus, the bottom portion still lagged behind the top
portion to reach an average temperature
near a pyrolysis temperature but the time lag was less than the time lag in
the first example.
FIG. 207 depicts net heater energy input (Btu) versus time (days) for the
second example. Curve 1466
depicts net heater energy input for the bottom portion. Curve 1468 depicts net
heater input for the top portion. The
net heater energy input to reach a temperature of 340 C (644 F) for the
bottom portion was 2.35 x 101 Btu. The
net heater energy input to reach a temperature of 340 C (644 F) for the top
portion was 1.32 x 10' Btu. Thus, it
took 12% more power to reach the desired temperature in the bottom portion.
FIG. 208 depicts power injection per foot (W/ft) versus time (days) for the
second example. Curve 1470
depicts power injection rate for the bottom portion. Curve 1472 depicts power
injection rate for the top portion. The
power injection rate for the bottom portion was about 6% more than the power
injection rate for the top portion.
Thus, either reducing the power output of the top portion and/or increasing
the power output of the bottom portion to
a total of about 6% should provide approximately similar heating rates in the
top and bottom portions.
In the third example, dimensions of the top portion (portion 550) were altered
to provide less power output.
Portion 550 was adjusted to have a copper core with an outside diameter of
13.84 millimeter (0.545 inch), a carbon
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CA 02871784 2014-11-18
steel conductor with an outside diameter of 17.78 millimeter (0.700 inch)
surrounding the copper core, and an outer
conductor of 347H stainless steel with an outside diameter of 30.48 millimeter
(1.2 inch) surrounding the carbon
steel conductor. The bottom portion (portion 548) had the same properties as
the heater in the second example. FIG.
209 depicts resistance per foot (me/ft) versus temperature ( F) for the third
heater example. Curve 1474 depicts the
resistance profile for the top portion (portion 550). Curve 1476 depicts the
resistance profile of the top portion in the
second example. Curve 1478 depicts the resistance profile for the bottom
portion (portion 548). FIG. 210 depicts
average temperature in the formation ( F) versus time (days) as determined by
the simulation for the third example.
Curve 1480 depicts average temperature versus time for the top portion of the
formation. Curve 1482 depicts
average temperature versus time for the bottom portion of the formation. As
shown, the average temperature in the
bottom portion of the formation was approximately the same as the average
temperature in the top portion of the
formation, especially after a time of about 1000 days. The top portion of the
formation reached an average
temperature of 340 C (644 F) in 1642 days. The bottom portion of the
formation reached an average temperature
of 340 C (644 F) in 1649 days. Thus, the bottom portion reached an average
temperature near a pyrolysis
temperature only 5 days later than the top portion.
FIG. 211 depicts cumulative energy injection (Btu) versus time (days) for each
of the three heater examples.
Curve 1484 depicts cumulative energy injection for the first heater example.
Curve 1486 depicts cumulative energy
injection for the second heater example. Curve 1488 depicts cumulative energy
injection for the third heater
example. The second and third heater examples have nearly identical cumulative
energy injections. The first heater
example had a cumulative energy injection about 7% higher to reach an average
temperature of 340 C (644 F) in
the bottom portion.
FIGS. 202-211 depict results for heaters with a 40 foot spacing between
heaters in a triangular heating
pattern. FIG. 212 depicts average temperature ( F) versus time (days) for the
third heater example with a 30 foot
spacing between heaters in the formation as determined by the simulation.
Curve 1490 depicts average temperature
versus time for the top portion of the formation. Curve 1492 depicts average
temperature versus time for the bottom
portion of the formation. The curves in FIG. 212 still tracked with
approximately equal heating rates in the top and
bottom portions. The time to reach an average temperature in the portions was
reduced. The top portion of the
formation reached an average temperature of 340 C (644 F) in 903 days. The
bottom portion of the formation
reached an average temperature of 340 C (644 F) in 884 days. Thus, the
reduced heater spacing decreases the time
needed to reach an average selected temperature in the formation.
As a fourth example, the STARS simulation was used to determine heating
properties of temperature
limited heaters with varying power outputs when using the temperature limited
heaters in the heater configuration
and pattern depicted in FIGS. 65 and 67. The heater pattern had a 30 foot
heater spacing. Portion 550 had a length
of 368 feet and portion 548 had a length of 587 feet as in the previous
examples. Portion 550 included a solid 410
stainless steel conductor with an outside diameter of 31.75 millimeter (1.25
inch). Portion 548 included a solid 410
stainless steel conductor with 9% by weight cobalt added. The Curie
temperature of portion 548 is 110 C (230 F)
higher than the Curie temperature of portion 550.
FIG. 213 depicts average temperature ( F) versus time (days) for the fourth
heater example using the heater
configuration and pattern depicted in FIGS. 65 and 67 as determined by the
simulation. Curve 1494 depicts average
temperature versus time for the top portion of the formation. Curve 1496
depicts average temperature versus time
for the bottom portion of the formation. The curves in FIG. 213 show
approximately equal heating rates in the top
and bottom portions. The top portion of the formation reached a temperature of
340 C (644 F) in 859 days. The
bottom portion of the formation reached a temperature of 340 C (644 F) in
880 days. In this heater configuration
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and heater pattern, the top portion of the formation reached a selected
temperature at about the same time as a
bottom portion of the formation.
Tar Sands Simulation
A STARS simulation was used to simulate heating of a tar sands formation using
the heater well pattern
depicted in FIG. 98. The heaters had a horizontal length in the tar sands
formation of 600 m. The heating rate of the
heaters was about 750 W/m. Production well 206B, depicted in FIG. 98, was used
at the production well in the
simulation. The bottom hole pressure in the horizontal production well was
maintained at about 690 kPa. The tar
sands formation properties were based on Athabasca tar sands. Input properties
for the tar sands formation
simulation included: initial porosity equals 0.28; initial oil saturation
equals 0.8; initial water saturation equals 0.2;
initial fee gas saturation equals 0.0; initial vertical permeability equals
250 millidarcy; initial horizontal permeability
equals 500 millidarcy; initial Kv/Kh equals 0.5; hydrocarbon layer thickness
equals 28 m; depth of hydrocarbon layer
equals 587 m; initial reservoir pressure equals 3771 kPa; distance between
production well and lower boundary of
hydrocarbon layer equals 2.5 meter; distance of topmost heaters and overburden
equals 9 meter; spacing between
heaters equals 9.5 meter; initial hydrocarbon layer temperature equals 18.6
C; viscosity at initial temperature equals
53 Pas (53000 cp); and gas to oil ratio (GOR) in the tar equals 50 standard
cubic feet/standard barrel. The heaters
were constant wattage heaters with a highest temperature of 538 C at the sand
face and a heater power of 755 W/m.
The heater wells had a diameter of 15.2 cm.
FIG. 214 depicts a temperature profile in the formation after 360 days using
the STARS simulation. The
hottest spots are at or near heaters 716. The temperature profile shows that
portions of the formation between the
heaters are warmer than other portions of the formation. These warmer portions
create more mobility between the
heaters and create a flow path for fluids in the formation to drain downwards
towards the production wells.
FIG. 215 depicts an oil saturation profile in the formation after 360 days
using the STARS simulation. Oil
saturation is shown on a scale of 0.00 to 1.00 with 1.00 being 100% oil
saturation. The oil saturation scale is shown
in the sidebar. Oil saturation, at 360 days, is somewhat lower at heaters 716
and production well 206B. FIG. 216
depicts the oil saturation profile in the formation after 1095 days using the
STARS simulation. Oil saturation
decreased overall in the formation with a greater decrease in oil saturation
near the heaters and in between the
heaters after 1095 days. FIG. 217 depicts the oil saturation profile in the
formation after 1470 days using the STARS
simulation. The oil saturation profile in FIG. 217 shows that the oil is
mobilized and flowing towards the lower
portions of the formation. FIG. 218 depicts the oil saturation profile in the
formation after 1826 days using the
STARS simulation. The oil saturation is low in a majority of the formation
with some higher oil saturation
remaining at or near the bottom of the formation in portions below production
well 206B. This oil saturation profile
shows that a majority of oil in the formation has been produced from the
formation after 1826 days.
FIG. 219 depicts the temperature profile in the formation after 1826 days
using the STARS simulation. The
temperature profile shows a relatively uniform temperature profile in the
formation except at heaters 716 and in the
extreme (corner) portions of the formation. The temperature profile shows that
a flow path has been created between
the heaters and to production well 206B.
FIG. 220 depicts oil production rate 1498 (bbl/day)(left axis) and gas
production rate 1500 (ft3/day)(right
axis) versus time (years). The oil production and gas production plots show
that oil is produced at early stages (0-1.5
years) of production with little gas production. The oil produced during this
time was most likely heavier mobilized
oil that is unpyrolyzed. After about 1.5 years, gas production increased
sharply as oil production decreased sharply.
The gas production rate quickly decreased at about 2 years. Oil production
then slowly increased up to a maximum
production around about 3.75 years. Oil production then slowly decreased as
oil in the formation was depleted.
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From the STARS simulation, the ratio of energy out (produced oil and gas
energy content) versus energy in
(heater input into the formation) was calculated to be about 12 to 1 after
about 5 years. The total recovery
percentage of oil in place was calculated to be about 60% after about 5 years.
Thus, producing oil from a tar sands
formation using an embodiment of the heater and production well pattern
depicted in FIG. 98 may produce high oil
recoveries and high energy out to energy in ratios.
Nanofiltration Example
A liquid sample (500 mL, 398.68 grams) was obtained from an in situ heat
treatment process. The liquid
sample contained 0.0069 grams of sulfur and 0.0118 grams of nitrogen per gram
of liquid sample. The final boiling
point of the liquid sample was 481 C and the liquid sample had a density of
0.8474. The membrane separation unit
used to filter the sample was a laboratory flat sheet membrane installation
type P28 as obtained from CM Celfa
Membrantechnik A.G. (Switzerland). A single 2-micron thick poly di-methyl
siloxane membrane (GKSS
Forschungszentrum GmbH, Geesthact, Germany) was used as the filtration medium.
The filtration system was
operated at 50 C and a pressure difference over the membrane was 10 bar. The
pressure at the permeate side was
nearly atmospheric. The permeate was collected and recycled through the
filtration system to simulate a continuous
process. The permeate was blanketed with nitrogen to prevent contact with
ambient air. The retentate was also
collected for analysis. During filtration the average flux of 2 kg/m2/bar/hr
did not measurably decline from an initial
flux during the filtration. The filtered liquid (298.15 grams, 74.7% recovery)
contained 0.007 grams of sulfur and
0.0124 grams of nitrogen per gram of filtered liquid; and the filtered liquid
had a density of 0.8459 and a final
boiling point of 486 C. The retentate (56.46 grams, 14.16% recovery)
contained 0.0076 grams of sulfur and 0.0158
grams of nitrogen per gram of retentate; and the retentate had a density of
0.8714 and a final boiling point of 543 C.
Fouling Testing Example
The unfiltered and filtered liquid samples from previous Example were tested
for fouling behavior. Fouling
behavior was determined using an Alcor thermal fouling tester. The Alcor
thermal fouling tester is a miniature shell
and tube heat exchanger made of 1018 steel which was grated with Norton R222
sandpaper before use. During the
test the sample outlet temperature, (Tout) was monitored while the heat-
exchanger temperature (Tc) was kept at a
constant value. If fouling occurs and material is deposited on the tube
surface, the heat resistance of the sample
increases and consequently the outlet temperature decreases. Hence the
decrease in outlet temperature after a given
period of time is a measure of fouling severity. The temperature decrease
after two hours of operation is used as
fouling severity indicator. AT = Touqo ¨ Tout(2h) T0ut(0) is defined as the
maximum (stable) outlet temperature obtained
at the start of the test, Tout(2h) is recorded 2 hours after the first noted
decrease of the outlet temperature or when the
outlet temperature has been stable for at least 2 hours.
During each test, the liquid sample was continuously circulated through the
heat exchanger at
approximately 3 mL/min. The residence time in the heat exchanger was about 10
seconds. The operating conditions
were as follows: 40 bar of pressure, Tsampie was about 50 C, Ic was 350 C,
test time was 4.41 hours. The AT for the
unfiltered liquid stream sample was 15 C. The AT for the filtered sample was
zero.
This example demonstrates that nanofiltration of a liquid stream produced from
an in situ heat treatment
process removes at least a portion of clogging compositions.
Olefin Production Example
An experimental pilot system was used to conduct the experiments. The pilot
system included a feed
supply system, a catalyst loading and transfer system, a fast fluidized riser
reactor, a stripper, a product separation
and collecting system, and a regenerator. The riser reactor was an adiabatic
riser having an inner diameter of from
11 mm to 19 mm and a length of about 3.2 m. The riser reactor outlet was in
fluid communication with the stripper
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that was operated at the same temperature as the riser reactor outlet flow and
in a manner to provide essentially 100
percent stripping efficiency. The regenerator was a multi-stage continuous
regenerator used for regenerating the
spent catalyst. The spent catalyst was fed to the regenerator at a controlled
rate and the regenerated catalyst was
collected in a vessel. Material balances were obtained during each of the
experimental runs at 30-minute intervals.
Composite gas samples were analyzed by use of an on-line gas chromatograph and
the liquid product samples were
collected and analyzed overnight. The coke yield was measured by measuring the
catalyst flow and by measuring
the delta coke on the catalyst as determined by measuring the coke on the
spent and regenerated catalyst samples
taken for each run when the unit was operating at steady state.
A liquid stream produced from an in situ heat treatment process was fractioned
to obtain a vacuum gas oil
(VG0) stream having a boiling range distribution from 310 C to 640 C. The VG0
stream was contacted with a
fluidized catalytic cracker E-Cat containing 10% ZSM-5 additive in the
catalytic system described above. The riser
reactor temperature was maintained at 593 C (1100 F). The product produced
contained, per gram of product,
0.1402 grams of C3 olefins, 0.137 grams of C4 olefins, 0.0897 grams of C5
olefins, 0.0152 grams of iso-05 olefins,
0.0505 grams isobutylene, 0.0159 grams of ethane, 0.0249 grams of isobutane,
0.0089 grams of n-butane, 0.0043
grams pentane, 0.0209 grams iso-pentane, 0.2728 grams of a mixture of C6
hydrocarbons and hydrocarbons having a
boiling point of at most 232 C (450 F), 0.0881 grams of hydrocarbons having
a boiling range distribution between
232 C and 343 C (between 450 F and 650 F), 0.0769 grams of hydrocarbons
having a boiling range distribution
between 343 C and 399 C (650 F and 750 F) and 0.0386 grams of hydrocarbons
having a boiling range
distribution of at least 399 C (750 F) and 0.0323 grams of coke.
This example demonstrates a method of producing crude product by fractionating
liquid stream produced
from separation of the liquid stream from the formation fluid to produce a
crude product having a boiling point
above 343 C; and catalytically cracking the crude product having the boiling
point above 343 C to produce one or
more additional crude products, wherein least one of the additional crude
products is a second gas stream.
Production of Olefins From A Liquid Stream Example
A thermally cracked naphtha was used to simulate a liquid stream produced from
an in situ heat treatment
process having a boiling range distribution from 30 C to 182 C. The naphtha
contained, per gram of naphtha,
0.186 grams of naphthenes, 0.238 grams of isoparaffins, 0.328 grams of n-
paraffins, 0.029 grams cyclo-olefins,
0.046 grams of iso-olefins, 0.064 grams of n-olefins and 0.109 grams of
aromatics. The naphtha stream was
contacted with a FCC E-Cat with 10% ZSM-5 additive in the catalytically
cracking system described above to
produce a crude product. The riser reactor temperature was maintained at 593
C (1100 F). The crude product
included, per gram of crude product, 0.1308 grams ethylene, 0.0139 grams of
ethane, 0.0966 grams C4-olefins,
0.0343 grams C4 iso-olefins, 0.0175 grams butane, 0.0299 grams isobutane,
0.0525 grams C5 olefins, 0.0309 grams
C5 iso-olefins, 0.0442 grams pentane, 0.0384 grams iso-pentane, 0.4943 grams
of a mixture of C6 hydrocarbons and
hydrocarbons having a boiling point of at most 232 C (450 F), 0.0201 grams
of hydrocarbons having a boiling
range distribution between 232 C and 343 C (between 450 F and 650 F),
0.0029 grams of hydrocarbons having a
boiling range distribution between 343 C and 399 C (650 F and 750 F) and
0.00128 grams of hydrocarbons
having a boiling range distribution of at least 399 C (750 F) and 0.00128
grams of coke. The total amount of C3-
C5 olefins was 0.2799 grams per gram of naphtha.
This example demonstrates a method of producing crude product by fractionating
liquid stream produced
from separation of the liquid stream from the formation fluid to produce a
crude product having a boiling point
above 343 C; and catalytically cracking the crude product having the boiling
point above 343 C to produce one or
more additional crude products, wherein least one of the additional crude
products is a second gas stream.
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Further modifications and alternative embodiments of various aspects of the
invention may 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
the presently preferred 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. In addition, it is to be understood that features described herein
independently may, in certain
embodiments, be combined. The scope of the claims should not be limited by the
preferred embodiments set
forth in the examples, but should be given the broadest interpretation
consistent with the description as a whole.
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Reference Number Table
barrier wells 200 200 200
heat sources 202 202 202
supply lines 204 204 204
Production wells 206 206 206
collection piping 208 208 208 .
treatment facilities 210 _ 210 210
Line 212 212 212
Heat x 1 214 214 214
Line 2 216 216 216
Tank 218 218 218
Pump 220 220 220
Heat x 2 222 222 222
Separator 224 224 224
Turbine 226 226 226
Heat x 3 228 228 228
Line 230 230 230
Heat x 4 232 232 232
Heat x 5 234 234 234
Heat x 6 236 236 236
Heat x 7 238 238 238
ICP gas 240 240 240
Unit 242 242 242
Gs 244 244 244
Hydrogen source 246 246 246
Hydr reactor 248 248 248
Gs 250 250 250
Heavy byproducts 252 252 252
H2 sep unit 254 254 254
H2 rich stream 256 256 256
Gs 258 258 258
Ox unit 260 260 260
Inlet stream 262 262 262
Gs 264 264 264
Dehydration unit 266 266 266
Pipeline gas 268 268 268
Water 270 270 270
Steam 272 272 272
Reforming unit 274 274 274
Reforming Unit exit gas 276 276 276
Methanation unit 278 278 278
Methanation unit_exit_gas 280 280 280
CO2 scrubber 282 282 282
CO2 scrubber_exit_gas 284 284 284
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CO2 stream 286 286 286
Hydrogenation/methanation unit 288 288 288
Hyd/Meth exit gas stream 290 290 290
Polishing unit 292 292 292
PU_carbon dioxide stream 294 294 294
PU_gas stream exiting 296 296 - 296
Hydrogenation/methanation unit +CO2 298 298 298
Hydrogenation/methanation unit +CO2 exit 300 300 300
gas
Heat exchanger 302 302 302
Dehydrator_exit_gas 304 304 304
Cryogenic separator 306 306 306
Hydrocarbons greater than 2 308 308 308
Hydrogentation/methanation unit + H2 310 310 310
Hydrogentation/methanation unit + H2_exit 312 312 312
gas
Gas Separation unit 314 314 314
.. .
Gas separations unit exit gas 316 316 316
H2 recycle stream 318 318 318
Formation fluid 320 320 320
Separation unit 322 322 322
ICP liquid 324 324 324
Aqueous stream 326 326 326
Gas separation unit 328 328 328
Gsu exit gas 330 330 330
Liquid separation unit 332 332 332
Liquid stream 334 334 334
CS-stream 336 336 336
Salty liquid stream Pct230 338 338
Desalter Pct232 ' 340 340
Filtration System Pct236 342 342
Filtered liquid stream - Pct238 344 344
Recycle stream Pct240 346 346
Waste stream Pct242 348 348
Hydrotreating unit Pct248 350 350
Spec. 338
Hydrotreating exit liquid 340 352 352
Distillation unit 342 354 354
C3-c5 hydrocarbon stream 344 356 356
Naphtha stream 346 358 358
Kerosene stream 348 360 360
Diesel stream 350 362 362
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VGO stream 352 364 364
Heavies hydrocarbons stream 354 366 366
Alkylation unit 356 368 368
Alkylation unit exit stream 358 370 370
Cat. Cracker 360 372 372
Gasoline 362 374 374
Liquid Stream to MILOS Pct274 376 376
Catalytic cracking system Pct278 378 378
Used CC catalyst Pct280 380 380
Regen CC catalyst Pct282 382 ' 382
Light hydrocarbon catalytic cracking Pct284 384 384
system
MILOS_separator Pct286 386 386
Spent catalyst Pct288 388 388
Regenerator Pct290 390 390
. Oxygen source Pct292 392 392
Combustion gas Pct294 394 394
Crude Product Pct296 396 396
MILOS_Iiquid separation unit Pct298 398 398
Cracked gasoline product stream Pct300 400 400
Light cycle oil Pct302 402 402
Bottom stream Pct304 404 404
Gas oil hydrocarbon stream Pct306 406 406
Gas stream Pct308 408 408
Olefin separation system Pct310 410 410
Ethylene stream Pct312 412 412
Propylene stream Pct314 414 414
Butylene stream Pct316 416 416
Bit 364 418 418
Skirt 366 420 420
Annulus 368 422 422
bottom portion 370 424 424
Cutters 372 426 426
Opening 374 428 428
Drill rod center 376 430 430
Pilot bit 378 ' 432 432
Final D bit 380 434 434
Conduit 382 436 436
_
Closed loop system 384 438 438
204
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,
freeze wells 408 440 440
Freeze well casing 410 442 442
inlet conduit 412 , 444 444
spacers 414 446 446
wellcap 416 448 448
wellhead 418 450 450
Wellbore 420 452 452
cold side conduit 417 _ 454 454
warm side conduit 419 456 456
overburden 382 458 458
hydrocarbon layer 380 460 460
Fracture system 390 462 462
Conduit 392 464 464
Low T heater 394 466 466
wax 492 492
= Insert 506 468 468
Balls 508 470 470
Heater element 510 472 472
Metal strip 596 474 474
coil 598 476 476
shield 600 478 478
gas inlets 602 480 480
window 604 482 482
Tubular 606 484 484
_
ferromagnetic section 622 486 486
non-ferromagnetic section 624 488 488
Inner conductor 626 490 490
Electrical insulator 628 500 500
Outer conductor 630 502 , 502
conductive section 632 504 504
jacket 636 506 506
Core 656 508 508
conductive layer 634 510 510
ferromagnetic conductor 654 512 512
support member 662 , 514 514
conductor 666 516 516
conduit 668 518 518
,
low resistance sections 670 520 520
opening 378 522 522
centralizer 672 524 524
_
power cable 676 526 526
sliding connector 678 528 528
overburden casing 680 530 530
packing material 520 532 532
Surface or ground 550 534 534
205
CA 02871784 2014-11-18
1
conduit _ 682 1 536 536
_
Electrical conductor 716 538 538
- _
718 - 540 540
542
544
546
- 7= 26 548 548
728 550 550
730 552 - 5= 52
,-
transition section 732 ' 554 - 5= 54
736 556 556
insulated conductor 712 558 - 5= 58
738 560 - 5= 60
Coiled tubing rig 740 562 562
straps 742 564 - 5= 64
_
contactor section 744 566 566
termination 746 568 _ 568
core coupling material , 650 570 , 570
Coupling material 660 572 572
shield 748 574 574
Upper plate - 7= 50 576 576
Lower plate - 7= 52 578 578
inserts - 7= 54 580 580
wall - 7= 56 582 582
Hinged door - 7= 58 584 584
_
1 st clamp member - 7= 60 586 586
2nd clamp member - 7= 62 588 588
Viewing window - 7= 64 590 590
Orbital welder ' 7= 66 600 600
Inlet - 7= 68 602 602
Purge 770 604 604
Power supply - 7= 72 606 606
Line - 7= 74 608 608
Line 776 610 610
,-
switch 778 612 612
_
monitor 780 614 614
Endcap 642 _ 616 616
leg_ 792 618 618
terminal block 794 _ 620 620
insulation material 796 622 622
legs 798 624 624
-
legs 800 626 626
legs 802 628 628
Heating element - 8= 04 v 630 630
206
CA 02871784 2014-11-18
contacting element 806 632 632
8
transformer 16 634 634
lead-in cable 692 636 636
transition section 818 638 638
Contactor 812 640 640
,
'
section 8= 08 642 642
r
solution 814 644 644
first location 878 646 646
connector 886 648 648
second location 884 650 650
triad ,-
820 , 652 652
-
linkage 822 654 654
hexagon 824 656 656
container
834 658 _ 658
heating element - 836 660 ,. 660
lead-in wire 838 662 ,, 662
Lead-out wire 840 664 664
8
Protrusions 42 666 666
8
Protrusions 44 668 668
coupling material 846 670 670
container insulation layer 848 672 672
container liner 850 674 674
powder 852 676 676
igniter 854 678 678
-8= 56 , 680 680
- insulation heating element - 8= 58 , 682 682
-
_
inner container
8= 60 _684 684
862 ,_686 , 686 688 688
outer container
864
-- opening _
opening 866 690 690
explosive element 868 700 700
702
870 702
battery _
=
timer 872 704 704
-
Trigger
874 706 706
_
brush contactor 300 876 708 708
opening 810 710 710
diad D100 712
groups D102 714
Heater 880 716 716
sections 888 718 718
transition sections 892 720 720
Cable 894 722 722
Cable 2 896 724 _ 724
'
bus bar 898 726 726
-
9
transformer 00 728 728
Center conductor 902 730 730
coupling 904 732 732
-
-
arrows TLH102 734 734
arrows TLI-1104 736 736
207
CA 02871784 2014-11-18
openings TLH100 738 738
impermeable zones 468 740 740
links 906 . 742 742
well plug 908 744 744
_
shale break TS216 746 746
injection well 916 748 748
facility 918 750 750
facility 920 752 752
-
production conduit 512 754 754
wellbore 922 756 756
formation 444 758 758
heater 534 760 760
Heating/production assembly 924 762 762
opening 926 764 764
perforated casing 928 766 766
seal assembly 920 768 768
feedthrough 932 770 770
clamp 934 772 772
valves 936 774 774
production conduit 938 776 776
pump 518 778 778
. perforations 940 780 780
insulation conduit 942 782 782
hot portion 944 784 784
warm portion 946 786 786
overburden portion 948 788 788
coke 950 790 790
Oxidizer assembly Gb1102 800 800
Oxidizer - Gb1104 802 802
Fuel Gb1106 804 804
Fuel conduit Gb1108 806 806
Oxidizing fluid Gb1110 - 808 808
Oxidizer conduit Gb1112 810 810
Exhaust gas Gb1114 812 812
Outer conduit Gb1116 814 814
_
Igniter Gb00 816 816
Mix chamber Gb01 818 818
Igniter holder Gb02 820 820
Nozzle and flame holder Gb03 822 822
Heat shield Gb04 824 824
Fuel opening Gb045 826 826
Openings Gb05 828 828
Opening Gb06 830 830
Openings Gb07 832 832
Heat shield spacer Gb08 834 834
Flame stabilizer Gb09 836 836
208
CA 02871784 2014-11-18
Catalytic burner Gb10 838 838
Catalyst Gb I 1 840 840
Autoignition zone Gb12 842 842
Main combustion zone Gb13 844 844
Pre-heat zone Gb14 846 846
_
Gas turbine 1520 848 848
electrical generator 1522 850 850
turbine gas combustor 1524 852 852
Inlet leg 1526 854 854
Oxidant line 1528 856 856
_
Fuel line 1530 858 858
temperature limited heater 1532 860 860
Lead in cable 1534 862 862
_
tubular 1536 864 864
Outlet 1538 866 866
circulation system 1540 868 868
furnace 1542 870 870
first heat exchanger 1544 872 872
second heat exchanger 1546 874 874
compressor 1548 876 876
entries 1550 878 878
exits 1552 880 880
treatment area 424 882 882
Helium blower nr I 884 884
Nuclear reactor Nr2 886 886
Heat exchanger unit Nr3 888 888
Ht fluid blower Nr4 890 890
Auxiliary power unit Nr5 900 900
Well opening area Nr6 902 902
Rail lines Nr7 904 904
Facilities Nr8 906 906
Electrical power supply 1554 908 908
section GS5000 910
section GS5002 912
section GS5004 914
section GS5006 916
section GS5008 918
checkerboard pattern GS5100 920
_
first barrier 454 922 922
Migration inhibition wells mis , 924 924
Windmill 1560 926 926
Gas turbine 1562 928 928
209
CA 02871784 2014-11-18
transformer 1564 930 930
ATC 1566 932 932
Computer 1568 934 934
Power sensors 1570 936 936
Smw Sm212 938 938
Insulated portion Sm214 940 940
Input Sm216 942 942
packer Sm218 944 944
Return Sm220 946 946
Casing Sm226 948 948
Unleached zone Sm228 950 950
Leached zone Sm230 952 952
pumping/monitor wells 462 956 956
Zone 1572 958 958
Gas wells 1574 960 960
Front 1576 962 962
curve 952 964 964
curve 954 966 966
curve 956 968 968
curve 958 970 970
curve 960 972 972
curve 962 974 974
curve 964 976 976
curve 966 978 978
curve 968 980 980
curve 970 982 982
curve 972 984 984
curve 974 986 986
curve 976 988 988
curve 978 990 990
curve 980 1000 1000
curve 982 1002 1002
curve 984 1004 1004
curve 986 1006 1006
curve 988 1008 1008
curve 990 1010 1010
curve 992 1012 1012
curve 994 1014 1014
curve 996 1016 1016
curve 998 1018 1018
curve 1000 1020 1020
curve 1002 1022 1022
curve 1004 1024 1024
curve 1006 1026 1026
curve 1008 1028 1028
curve 1010 1030 1030
curve 1012 1032 1032
curve 1014 1034 1034
curve 1016 1036 1036
curve 1018 1038 1038
curve 1020 1040 1040
curve 1022 1042 1042
curve 1024 1044 1044
curve 1026 1046 1046
curve 1028 1048 1048
curve 1030 1050 1050
curve 1032 1052 1052
210
CA 02871784 2014-11-18
curve 1034 1054 1054
Curve 1036 1056 1056
Curve 1038 1058 1058
Curve 1040 1060 1060
Curve 1042 1062 1062
Curve 1044 1064 1064
Curve 1046 1066 1066
Curve 1048 1068 1068
Curve 1050 1070 1070
Curve 1052 1072 1072
Curve 1054 1074 1074
Curve 1056 1076 1076
Curve 1058 1078 1078
Curve 1060 1080 1080
Curve 1062 1082 1082
Curve 1064 1084 1084
Curve 1066 1086 1086
curve 1086 1088 1088
curve 1088 1090 1090
curve 1090 1092 1092
_ curve 1092 _ 1094 1094
curve 1094 1096 1096
- curve 1096 1098 1098
_
curve 1098 1100 1100
curve 1100 1102 1102
curve 1102 1104 1104
curve 1104 1106 1106
_
curve 1106 1108 1108
curve 1108 _ 1110 1110
curve 1110 _ 1112 1112
curve 1112 1114 1114
curve 1114 1116 _ 1116
curve 1116 1118 1118
curve 1118 1120 1120
data 1120 1122
data 1122 1124
data 1124 1126
curve 1126 1128
data 1128 1130
data 1130 1132
curve 1132 1134 _
curve 1134 1136
curve 1136 1138
1138 1140
1140 1142
1142 1144
1144 1146
1146 1148
1148 1150
1150 1152
1152 1154
1154 1156
1156 1158
1158 1160
1160 1162
211
CA 02871784 2014-11-18
1162 1164
1164 1166
1166 1168
1168 1170
1170 1172
1172 1174
1174 1176
1176 1178
1178 1180
1180 1182
1182 1184
1184 1186
1186 1188
1188 1190
1190 1192
1192 1194
1194 1196
1196 1198
1198 1200
curve 1200 1202 1202
curve 1202 1204 1204
curve 1204 1206 1206
curve 1206 1208 1208
curve 1208 1210 1210
curve 1210 1212 1212
curve 1212 1214 1214
curve 1214 1216 1216
curve 1216 1218 1218
curve 1218 1220 1220
curve 1220 1222 1222
curve 1222 1224 1224
curve 1224 1226 1226
curve 1226 1228 1228
curve 1228 1230 1230
curve 1230 1232 1232
curve 1232 1234 1234
curve 1232 1236 1236
curve 1234 1238 1238
_
curve 1236 1240 1240
curve 1238 1242 1242
curve 1240 1244 1244
curve 1244 1246 1246
curve 1246 1248 1248
curve 1248 1250 1250
_
curve 1250 1252 1252
curve 1252 1254 1254
curve 1254 1256 1256
curve 1256 1258 1258
curve 1258 1260 1260
curve 1260 1262 1262
curve 1262 1264 1264
212
CA 02871784 2014-11-18
I
curve 1264 1266 1266
curve 1266 1268 1268 _
curve 1268 1270 1270
_ curve 1270 1272 1272
_
curve 1272 1274 1274 ,
curve 1274 1276 1276 .
_
curve 1276 1278 1278 .
curve 1278 1280 1280
- _
curve 1280 1282 1282
curve 1282 1284 1284
-
curve 1284 1286 1286
_curve 1286 1288 1288
curve 1288 1290 1290 .
curve 1290 1292 1292
curve 1292 1294 .
_ 1294_
curve 1294 1296 1296
-
curve 1296 1298 1298
_
curve 1298 1300 1300 .
_curve 1300 1302 1302
curve 1302 1304 1304
_curve 1304 1306 1306 .
curve 1306 1308 1308 .
_
. curve 1308 1310 1310
. .
_
curve 1310 1312 1312
curve 1312 1314 1314 .
curve 1314 1316 1316 .
_
curve 1316 1318 1318
curve _ 1318 1320 1320 .
_
curve 1320 1322 1322 .
curve 1322 1324 _. 1324 .
_
curve 1324 1326 1326
_
curve 1326 1328 _ 1328
curve 1328 , 1330 1330
_
Curve 1330 1332 1332 .
Curve 1332 1334 1334
Curve 1334 1336 1336
Curve 1336 1338 1338 .
Curve 1338 1340 _ 1340
Curve , 1340 1342 1342
-
curve 826 1344 1344
curve 828 1346 , 1346
curve 830 1348 1348
curve 832 1350 1350
DATA 1344 1352
DATA 1346 1354 .
DATA 1348 1356
DATA 1350 1358 .
DATA 1352 1360
DATA 1354 1362
DATA 1356 1364 _
DATA 1358 1366
DATA 1360 1368 _
DATA 1362 1370
DATA 1364 1372
DATA 1366 1374 .
DATA 1368 1376 .
DATA 1370 1378
DATA 1372 1380
DATA 1374 1382 .
DATA 1376 1384
213
CA 02871784 2014-11-18
DATA 1378 1386 .
DATA 1380 1388
DATA 1382 _ 1390
DATA 1384 1392
DATA 1386 1394 1394
1388 1396 1396
-
M23C6 Dc01 1398 1398
MAC,N) Dc02 1400 1400 .
Z phase Dc03 , 1402 1402
Cu Dc04 1404 1404
¨
Sigma Dc05 1406 1406
Chi Dc06 1408 1408
-
G phase Dc07 1410 1410
-
Laves
Dc08 1412 1412
-
M(C,N) - Dc09 1414 1414 _
Curves Dc10 1416 1416
Dcll 1418 1418
Dc12 1420 1420
Dc13 1422 1422
Dc14 1424 1424
* Dc15 1426 1426
Bar 1442 1428 1428
Bar 1444 1430 1430
Bar 1446 1432 1432
'
Bar 1448 1434 1434
Bar 1450 1436 1436
Bar 1452 1438 1438
Bar 1454 1440 1440
Bar 1456 1442 1442
Bar 1458 1444 1444
Bar 1460 1446 1446
Bar 1462 1448 1448
=
CURVE 1470 1450
CURVE 1472 1452
CURVE 1474 1454
CURVE 1476 1456
CURVE 1478 1458
CURVE 1480 1460
CURVE 1482 1462
CURVE 1484 1464
CURVE 1486 1466
CURVE 1488 1468
-
CURVE 1490 1470
CURVE 1492 1472
CURVE 1494 1474
CURVE 1496 1476
214
CA 02871784 2014-11-18
CURVE 1498 1478
CURVE 1502 1480
CURVE 1500 1482
CURVE 1508 1484
CURVE 1506 1486
CURVE 1504 1488
CURVE 1510 1490
CURVE 1512 1492
CURVE 1514 1494
CURVE 1516 1496
oil production rate TS218 1498
gas production rate TS220 1500
215
