Note: Descriptions are shown in the official language in which they were submitted.
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
LOW TEMPERATURE INDUCTIVE HEATING OF SUBSURFACE FORMATIONS
BACKGROUND
1. Field of the Invention
[0001] The present invention relates generally to systems, methods and heat
sources for
production of hydrocarbons, hydrogen, and/or other products. The present
invention relates in
particular to systems and methods using heat sources for treating various
subsurface
hydrocarbon formations.
2. Description of Related Art
[0002] 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.
[0003] Subsurface formations (for example, tar sands or heavy hydrocarbon
formations)
include dielectric media. Dielectric media may exhibit conductivity, relative
dielectric
constant, and loss tangents. Loss of conductivity may occur as the formation
is heated to
temperatures above the boiling point of water in the formation (for example,
above 100 C)
due to the loss of moisture contained in the interstitial spaces in the rock
matrix of the
formation. To prevent loss of moisture, formations may be heated at
temperatures and
pressures that minimize vaporization of water. Conductive solutions may be
added to the
formation to help maintain the electrical properties of the formation.
[0004] Formations may be heated using electrodes to temperatures and pressures
that vaporize
the water and/or conductive solutions. Material used to produce the current
flow, however,
1
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
may become damaged due to heat stress and/or loss of conductive solutions may
limit heat
transfer in the layer. In addition, when using electrodes, magnetic fields may
form. Due to the
presence of magnetic fields, non-ferromagnetic materials may be desired for
overburden
casings.
[0005] U.S. Patent No. 4,084,637 to Todd describes methods of producing
viscous materials
from subterranean formations that includes passing electrical current through
the subterranean
formation. As the electrical current passes through the subterranean
formation, the viscous
material is heated to thereby lower the viscosity of such material. Following
the heating of the
subterranean formation in the vicinity of the path formed by the electrode
wells, a driving
fluid is injected through the injection wells to thereby migrate along the
path and force the
material having a reduced viscosity toward the production well. The material
is produced
through the production well and by continuing to inject a heated fluid through
the injection
wells, substantially all of the viscous material in the subterranean formation
can be heated to
lower its viscosity and be produced from the production well.
[0006] U.S. Patent No. 4,926,941 to Glandt et al. describes producing thick
tar sand deposits
by preheating of thin, relatively conductive layers which are a small fraction
of the total
thickness of a tar sand deposit. The thin conductive layers serve to confine
the heating within
the tar sands to a thin zone adjacent to the conductive layers even for large
distances between
rows of electrodes. The preheating is continued until the viscosity of the tar
in a thin preheated
zone adjacent to the conductive layers is reduced sufficiently to allow steam
injection into the
tar sand deposit. The entire deposit is then produced by steam flooding.
[0007] U.S. Patent No. 5,046,559 to Glandt describes an apparatus and method
for producing
thick tar sand deposits by electrically preheating paths of increased
injectivity between an
injector and producers. The injector and producers are arranged in a
triangular pattern with the
injector located at the apex and the producers located on the base of the
triangle. These paths
of increased injectivity are then steam flooded to produce the hydrocarbons.
[0008] As discussed 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 a need for improved methods and systems
for heating
2
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
of a hydrocarbon formation and production of fluids from the hydrocarbon
formation. There
is also a need for improved methods and systems that reduce energy costs for
treating the
formation, reduce emissions from the treatment process, facilitate heating
system installation,
and/or reduce heat loss to the overburden as compared to hydrocarbon recovery
processes that
utilize surface based equipment.
SUMMARY
[0009] 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.
[0010] 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.
[0011] In certain embodiments, a method for heating a hydrocarbon containing
formation
includes: providing time-varying electrical current at a first frequency to an
elongated
electrical conductor located in the formation; inducing electrical current
flow in a
ferromagnetic conductor with the time-varying electrical current at the first
frequency,
wherein the ferromagnetic conductor at least partially surrounds and at least
partially extends
lengthwise around the electrical conductor; resistively heating the
ferromagnetic conductor
with the induced electrical current flow such that the ferromagnetic conductor
resistively heats
up to a first temperature, wherein the first temperature is at most about 300
C; allowing heat
to transfer from the ferromagnetic conductor at the first temperature to at
least a part of the
formation; vaporizing at least some water in the formation with the
ferromagnetic conductor at
the first temperature; providing time-varying electrical current at a second
frequency to the
elongated electrical conductor; inducing electrical current flow in the
ferromagnetic conductor
with the time-varying electrical current at the second frequency; resistively
heating the
ferromagnetic conductor with the induced electrical current flow such that the
ferromagnetic
conductor resistively heats up to a second temperature, wherein the second
temperature is
above about 300 C; allowing heat to transfer from the ferromagnetic conductor
at the second
temperature to at least a part of the formation; and mobilizing at least some
hydrocarbons in
the part of the formation with the ferromagnetic conductor at the second
temperature.
3
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0012] 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.
[0013] In further embodiments, treating a subsurface formation is performed
using any of the
methods, systems, power supplies, or heaters described herein.
[0014] In further embodiments, additional features may be added to the
specific embodiments
described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] Features and advantages of the methods and apparatus of the present
invention will be
more fully appreciated by reference to the following detailed description of
presently preferred
but nonetheless illustrative embodiments in accordance with the present
invention when taken
in conjunction with the accompanying drawings.
[0016] FIG. 1 shows a schematic view of an embodiment of a portion of an in
situ heat
treatment system for treating a hydrocarbon containing formation.
[0017] FIG. 2 depicts a schematic of an embodiment for treating a subsurface
formation using
heat sources having electrically conductive material.
[0018] FIG. 3 depicts a schematic of an embodiment for treating a subsurface
formation using
a ground and heat sources having electrically conductive material.
[0019] FIG. 4 depicts a schematic of an embodiment for treating a subsurface
formation using
heat sources having electrically conductive material and an electrical
insulator.
[0020] FIG. 5 depicts a schematic of an embodiment for treating a subsurface
formation using
electrically conductive heat sources extending from a common wellbore.
[0021] FIG. 6 depicts a schematic of an embodiment for treating a subsurface
formation
having a shale layer using heat sources having electrically conductive
material.
[0022] FIG. 7 depicts an embodiment of a conduit with heating zone cladding
and a conductor
with overburden cladding.
[0023] FIG. 8 depicts an embodiment of a u-shaped heater that has an
inductively energized
tubular.
[0024] FIG. 9 depicts an embodiment of an electrical conductor centralized
inside a tubular.
[0025] FIG. 10 depicts an embodiment of an induction heater with a sheath of
an insulated
conductor in electrical contact with a tubular.
4
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0026] While the invention is susceptible to various modifications and
alternative forms,
specific embodiments thereof are shown by way of example in the drawings and
will herein be
described in detail. The drawings may not be to scale. It should be understood
that the
drawings and detailed description thereto are not intended to limit the
invention to the
particular form disclosed, but to 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
[0027] 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.
[0028] "Alternating current (AC)" refers to a time-varying current that
reverses direction
substantially sinusoidally. AC produces skin effect electricity flow in a
ferromagnetic
conductor.
[0029] 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).
[0030] "Coupled" means either a direct connection or an indirect connection
(for example,
one or more intervening connections) between one or more objects or
components. The
phrase "directly connected" means a direct connection between objects or
components such
that the objects or components are connected directly to each other so that
the objects or
components operate in a "point of use" manner.
[0031] "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.
[0032] 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"
5
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
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
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.
[0033] "Formation fluids" refer to fluids present in a formation and may
include pyrolyzation
fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation
fluids may
include hydrocarbon fluids as well as non-hydrocarbon fluids. The term
"mobilized fluid"
refers to fluids in a hydrocarbon containing formation that are able to flow
as a result of
thermal treatment of the formation. "Produced fluids" refer to fluids removed
from the
formation.
[0034] "Heat flux" is a flow of energy per unit of area per unit of time (for
example,
Watts/meter).
[0035] 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 electrically conducting materials and/or 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 electrically
conducting
materials, electric resistance heaters, some heat sources may provide heat
from combustion,
6
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
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 electrically conducting material and/or a
heater that provides
heat to a zone proximate and/or surrounding a heating location such as a
heater well.
[0036] A "heater" is any system or heat source for generating heat in a well
or a near wellbore
region. Heaters may be, but are not limited to, electric heaters, burners,
combustors that react
with material in or produced from a formation, and/or combinations thereof.
[0037] "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.
[0038] 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.
[0039] 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.
[0040] "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.
[0041] "Modulated direct current (DC)" refers to any substantially non-
sinusoidal time-
varying current that produces skin effect electricity flow in a ferromagnetic
conductor.
7
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0042] "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.
[0043] "Perforations" include openings, slits, apertures, or holes in a wall
of a conduit,
tubular, pipe or other flow pathway that allow flow into or out of the
conduit, tubular, pipe or
other flow pathway.
[0044] "Phase transformation temperature" of a ferromagnetic material refers
to a temperature
or a temperature range during which the material undergoes a phase change (for
example,
from ferrite to austenite) that decreases the magnetic permeability of the
ferromagnetic
material. The reduction in magnetic permeability is similar to reduction in
magnetic
permeability due to the magnetic transition of the ferromagnetic material at
the Curie
temperature.
[0045] "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.
[0046] "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.
[0047] "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.
[0048] 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.
8
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0049] "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.
[0050] "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).
[0051] "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.
[0052] "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.
[0053] "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).
[0054] "Turndown ratio" for the temperature limited heater in which current is
applied
directly to the 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.
Turndown ratio for an inductive heater is the ratio of the highest heat output
below the Curie
temperature to the lowest heat output above the Curie temperature for a given
current applied
to the heater.
[0055] 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".
[0056] 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."
9
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0057] A formation may be treated in various ways to produce many different
products.
Different stages or processes may be used to treat the formation during an in
situ heat
treatment process. In some embodiments, one or more sections of the formation
are solution
mined to remove soluble minerals from the sections. Solution mining minerals
may be
performed before, during, and/or after the in situ heat treatment process. In
some
embodiments, the average temperature of one or more sections being solution
mined may be
maintained below about 120 C.
[0058] In some embodiments, one or more sections of the formation are heated
to remove
water from the sections and/or to remove methane and other volatile
hydrocarbons from the
sections. In some embodiments, the average temperature may be raised from
ambient
temperature to temperatures below about 220 C during removal of water and
volatile
hydrocarbons.
[0059] In some embodiments, one or more sections of the formation are heated
to
temperatures that allow for movement and/or visbreaking of hydrocarbons in the
formation.
In some embodiments, the average temperature of one or more sections of the
formation are
raised to mobilization temperatures of hydrocarbons in the sections (for
example, to
temperatures ranging from 100 C to 250 C, from 120 C to 240 C, or from 150
C to 230
C)
[0060] In some embodiments, one or more sections are heated to temperatures
that allow for
pyrolysis reactions in the formation. In some embodiments, the average
temperature of one or
more sections of the formation may be raised to pyrolysis temperatures of
hydrocarbons in the
sections (for example, temperatures ranging from 230 C to 900 C, from 240 C
to 400 C or
from 250 C to 350 C).
[0061] Heating the hydrocarbon containing formation with a plurality of heat
sources may
establish thermal gradients around the heat sources that raise the temperature
of hydrocarbons
in the formation to desired temperatures at desired heating rates. The rate of
temperature
increase through mobilization temperature range and/or pyrolysis temperature
range for
desired products may affect the quality and quantity of the formation fluids
produced from the
hydrocarbon containing formation. Slowly raising the temperature of the
formation through
the mobilization temperature range and/or pyrolysis temperature range may
allow for the
production of high quality, high API gravity hydrocarbons from the formation.
Slowly raising
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
the temperature of the formation through the mobilization temperature range
and/or pyrolysis
temperature range may allow for the removal of a large amount of the
hydrocarbons present in
the formation as hydrocarbon product.
[0062] In some in situ heat treatment embodiments, a portion of the formation
is heated to a
desired temperature instead of slowly raising 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.
[0063] 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 a
desired temperature.
[0064] Mobilization and/or pyrolysis products may be produced from the
formation through
production wells. In some embodiments, the average temperature of one or more
sections is
raised to mobilization temperatures and hydrocarbons are produced from the
production wells.
The average temperature of one or more of the sections may be raised to
pyrolysis
temperatures after production due to mobilization decreases below a selected
value. In some
embodiments, the average temperature of one or more sections may be raised to
pyrolysis
temperatures without significant production before reaching pyrolysis
temperatures.
Formation fluids including pyrolysis products may be produced through the
production wells.
[0065] In some embodiments, the average temperature of one or more sections
may be raised
to temperatures sufficient to allow synthesis gas production after
mobilization and/or
pyrolysis. In some embodiments, hydrocarbons may be raised to temperatures
sufficient to
allow synthesis gas production without significant production before reaching
the
temperatures sufficient to allow synthesis gas production. 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. A synthesis gas generating fluid
(for example,
steam and/or water) may be introduced into the sections to generate synthesis
gas. Synthesis
gas may be produced from production wells.
[0066] Solution mining, removal of volatile hydrocarbons and water, mobilizing
hydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/or other
processes may
be performed during the in situ heat treatment process. In some embodiments,
some processes
11
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
may be performed after the in situ heat treatment process. Such processes may
include, but
are not limited to, recovering heat from treated sections, storing fluids (for
example, water
and/or hydrocarbons) in previously treated sections, and/or sequestering
carbon dioxide in
previously treated sections.
[0067] FIG. 1 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. 1, 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.
[0068] 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.
[0069] When the formation is heated, the heat input into the formation may
cause expansion
of the formation and geomechanical motion. The heat sources may be 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
12
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
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.
[0070] 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.
[0071] 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 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.
[0072] 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.
13
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0073] 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 hydrocarbons and above) in the production well, and/or (5)
increase
formation permeability at or proximate the production well.
[0074] 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 thermal expansion of in situ
fluids, 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.
[0075] In some hydrocarbon containing formations, production of hydrocarbons
from the
formation is inhibited until at least some hydrocarbons in the formation have
been mobilized
and/or 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 mobilized and/or 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.
[0076] In some hydrocarbon containing formations, hydrocarbons in the
formation may be
heated to mobilization and/or 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
14
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
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.
[0077] In some embodiments, pressure generated by expansion of mobilized
fluids, 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.
[0078] After mobilization and/or 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.
[0079] 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 20 . Maintaining increased pressure in the formation may inhibit
formation
subsidence during in situ heat treatment. 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.
[0080] 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
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
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.
[0081] 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. H2 in the
liquid phase may inhibit the generated pyrolyzation fluids from reacting with
each other
and/or with other compounds in the formation.
[0082] 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.
[0083] Subsurface formations (for example, tar sands or heavy hydrocarbon
formations)
include dielectric media. Dielectric media may exhibit conductivity, relative
dielectric
16
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
constant, and loss tangents at temperatures below 100 C. Loss of
conductivity, relative
dielectric constant, and dissipation factor may occur as the formation is
heated to temperatures
above 100 C due to the loss of moisture contained in the interstitial spaces
in the rock matrix
of the formation. To prevent loss of moisture, formations may be heated at
temperatures and
pressures that minimize vaporization of water. Conductive solutions may be
added to the
formation to help maintain the electrical properties of the formation.
[0084] Formations may be heated using electrodes to temperatures and pressures
that vaporize
the water and/or conductive solutions. Material used to produce the current
flow, however,
may become damaged due to heat stress and/or loss of conductive solutions may
limit heat
transfer in the layer. In addition, when using electrodes, magnetic fields may
form. Due to the
presence of magnetic fields, non-ferromagnetic materials may be desired for
overburden
casings.
[0085] Heat sources with electrically conducting material may allow current
flow through a
formation from one heat source to another heat source. Current flow between
the heat sources
with electrically conducting material may heat the formation to increase
permeability in the
formation and/or lower viscosity of hydrocarbons in the formation. Heating
using current
flow or "joule heating" through the formation may heat portions of the
hydrocarbon layer in a
shorter amount of time relative to heating the hydrocarbon layer using
conductive heating
between heaters spaced apart in the formation.
[0086] In some embodiments, heat sources that include electrically conductive
materials are
positioned in a hydrocarbon layer. Portions of the hydrocarbon layer may be
heated from
current generated from the heat sources that flows from the heat sources and
through the layer.
Positioning of electrically conductive heat sources in a hydrocarbon layer at
depths sufficient
to minimize loss of conductive solutions may allow hydrocarbons layers to be
heated at
relatively high temperatures over a period of time with minimal loss of water
and/or
conductive solutions.
[0087] FIGS. 2-6 depict schematics of embodiments for treating a subsurface
formation using
heat sources having electrically conductive material. FIG. 2 depicts first
conduit 230 and
second conduit 232 positioned in wellbores 224, 224' in hydrocarbon layer 212.
In certain
embodiments, first conduit 230 and/or second conduit 232 are conductors (for
example,
exposed metal or bare metal conductors). In some embodiments, conduits 230,
232 are
17
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
oriented substantially horizontally or at an incline in the formation.
Conduits 230, 232 may be
positioned in or near a bottom portion of hydrocarbon layer 212.
[0088] Wellbores 224, 224' may be open wellbores. In some embodiments, the
conduits
extend from a portion of the wellbore. In some embodiments, the vertical or
overburden
portions of wellbores 224, 224' are cemented with non-conductive cement or
foam cement.
Wellbores 224, 224' may include packers 228 and/or electrical insulators 234.
In some
embodiments, packers 228 are not necessary. Electrical insulators 234 may
insulate conduits
230, 232 from casing 216.
[0089] In some embodiments, the portion of casing 216 adjacent to overburden
218 is made of
material that inhibits ferromagnetic effects. The casing in the overburden may
be made of
fiberglass, polymers, and/or a non-ferromagnetic metal (for example, a high
manganese steel).
Inhibiting ferromagnetic effects in the portion of casing 216 adjacent to
overburden 218 may
reduce heat losses to the overburden and/or electrical losses in the
overburden. In some
embodiments, overburden casings 216 include non-metallic materials such as
fiberglass,
polyvinylchloride (PVC), chlorinated polyvinylchloride (CPVC), high-density
polyethylene
(HDPE), and/or non-ferromagnetic metals (for example, non-ferromagnetic high
manganese
steels). HDPEs with working temperatures in a range for use in overburden 218
include
HDPEs available from Dow Chemical Co., Inc. (Midland, Michigan, U.S.A.). In
some
embodiments, casing 216 includes carbon steel coupled on the inside and/or
outside 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 15% by
weight
manganese, 0.7% by weight carbon, 2% by weight chromium, iron aluminum alloys
with at
least 18% by weight aluminum, and austenitic stainless steels such as 304
stainless steel or
316 stainless steel.
[0090] Portions or all of conduits 230, 232 may include electrically
conductive material 236.
Electrically conductive materials include, but are not limited to, thick
walled copper, heat
treated copper ("hardened copper"), carbon steel clad with copper, aluminum,
or aluminum or
copper clad with stainless steel. Conduits 230, 232 may have dimensions and
characteristics
that enable the conduits to be used later as injection wells and/or production
wells. Conduit
230 and/or conduit 232 may include perforations or openings 238 to allow fluid
to flow into or
18
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
out of the conduits. In some embodiments, portions of conduit 230 and/or
conduit 232 are
pre-perforated with coverings initially placed over the perforations and
removed later. In
some embodiments, conduit 230 and/or conduit 232 include slotted liners.
[0091] After a desired time (for example, after injectivity has been
established in the layer),
the coverings of the perforations may be removed or slots may be opened to
open portions of
conduit 230 and/or conduit 232 to convert the conduits to production wells
and/or injection
wells. In some embodiments, coverings are removed by inserting an expandable
mandrel in
the conduits to remove coverings and/or open slots. In some embodiments, heat
is used to
degrade material placed in the openings in conduit 230 and/or conduit 232.
After degradation,
fluid may flow into or out of conduit 230 and/or conduit 232.
[0092] Power to electrically conductive material 236 may be supplied from one
or more
surface power supplies through conductors 240, 240'. Conductors 240, 240' may
be cables
supported on a tubular or other support member. In some embodiments,
conductors 240, 240'
are conduits through which electricity flows to conduit 230 or conduit 232.
Electrical
connectors 242 may be used to electrically couple conductors 240, 240' to
conduits 230, 232.
Conductor 240 and conductor 240' may be coupled to the same power supply to
form an
electrical circuit. Sections of casing 216 (for example a section between
packers 228 and
electrical connectors 242) may include or be made of insulating material (such
as enamel
coating) to prevent leakage of electrical current towards the surface of the
formation.
[0093] In some embodiments, a direct current power source is supplied to
either first conduit
230 or second conduit 232. In some embodiments, time varying current is
supplied to first
conduit 230 and/or second conduit 232. Current flowing from conductors 240,
240' to
conduits 230, 232 may be low frequency current (for example, about 50 Hz,
about 60 Hz, or
frequencies up to about 1000 Hz). A voltage differential between the first
conduit 230 and
second conduit 232 may range from about 100 volts to about 1200 volts, from
about 200 volts
to about 1000 volts, or from about 500 volts to 700 volts. In some
embodiments, higher
frequency current and/or higher voltage differentials may be utilized. Use of
time varying
current may allow longer conduits to be positioned in the formation. Use of
longer conduits
allows more of the formation to be heated at one time and may decrease overall
operating
expenses. Current flowing to first conduit 230 may flow through hydrocarbon
layer 212 to
19
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
second conduit 232, and back to the power supply. Flow of current through
hydrocarbon layer
212 may cause resistance heating of the hydrocarbon layer.
[0094] During the heating process, current flow in conduits 230, 232 may be
measured at the
surface. Measuring of the current entering conduits 230, 232 may be used to
monitor the
progress of the heating process. Current between conduits 230, 232 may
increase steadily
until a predetermined upper limit (Imax) is reached. In some embodiments,
vaporization of
water occurs at the conduits, at which time a drop in current is observed.
Current flow of the
system is indicated by arrows 244. Current flow in hydrocarbon containing
layer 212 between
conduits 230, 232 heats the hydrocarbon layer between and around the conduits.
Conduits
230, 232 may be part of a pattern of conduits in the formation that provide
multiple pathways
between wells so that a large portion of layer 212 is heated. The pattern may
be a regular
pattern (for example, a triangular or rectangular pattern) or an irregular
pattern.
[0095] FIG. 3 depicts a schematic of an embodiment of a system for treating a
subsurface
formation using electrically conductive material. Conduit 246 and ground 248
may extend
from wellbores 224, 224' into hydrocarbon layer 212. Ground 248 may be a rod
or a conduit
positioned in hydrocarbon layer 212 between about 5 m and about 30 m away from
conduit
246 (for example, about 10 m, about 15 m, or about 20 m). In some embodiments,
electrical
insulators 234' electrically isolate ground 248 from casing 216' and/or
conduit section 250
positioned in wellbore 224'. As shown, ground 248 is a conduit that includes
openings 238.
[0096] Conduit 246 may include sections 252, 254 of conductive material 236.
Sections 252,
254 may be separated by electrically insulating material 256. Electrically
insulating material
256 may include polymers and/or one or more ceramic isolators. Section 252 may
be
electrically coupled to the power supply by conductor 240. Section 254 may be
electrically
coupled to the power supply by conductor 240'. Electrical insulators 234 may
separate
conductor 240 from conductor 240'. Electrically insulating material 256 may
have
dimensions and insulating properties sufficient to inhibit current from
section 252 flowing
across insulation material 256 to section 254. For example, a length of
electrically insulating
material 256 may be about 30 meters, about 35 meters, about 40 meters, or
greater. Using a
conduit that has electrically conductive sections 252, 254 may allow fewer
wellbores to be
drilled in the formation. Conduits having electrically conductive sections
("segmented heat
sources") may allow longer conduit lengths. In some embodiments, segmented
heat sources
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
allow injection wells used for drive processes (for example, steam assisted
gravity drainage
and/or cyclic steam drive processes) to be spaced further apart, and thus
achieve an overall
higher recovery efficiency.
[0097] Current provided through conductor 240 may flow to conductive section
252 through
hydrocarbon layer 212 to a section of ground 248 opposite section 252. The
electrical current
may flow along ground 248 to a section of the ground opposite section 254. The
current may
flow through hydrocarbon layer 212 to section 254 and through conductor 240'
back to the
power circuit to complete the electrical circuit. Electrical connector 258 may
electrically
couple section 254 to conductor 240'. Current flow is indicated by arrows 244.
Current flow
through hydrocarbon layer 212 may heat the hydrocarbon layer to create fluid
injectivity in the
layer, mobilize hydrocarbons in the layer, and/or pyrolyze hydrocarbons in the
layer. When
using segmented heat sources, the amount of current required for the initial
heating of the
hydrocarbon layer may be at least 50% less than current required for heating
using two non-
segmented heat sources or two electrodes. Hydrocarbons may be produced from
hydrocarbon
layer 212 and/or other sections of the formation using production wells. In
some
embodiments, one or more portions of conduit 246 is positioned in a shale
layer and ground
248 is positioned in hydrocarbon layer 212. Current flow through conductors
240, 240' in
opposite directions may allow for cancellation of at least a portion of the
magnetic fields due
to the current flow. Cancellation of at least a portion of the magnetic fields
may inhibit
induction effects in the overburden portion of conduit 246 and the wellhead of
wellbore 224.
[0098] FIG. 4 depicts an embodiment in which first conduit 246 and second
conduit 246' are
used for heating hydrocarbon layer 212. Electrically insulating material 256
may separate
sections 252, 254 of first conduit 246. Electrically insulating material 256'
may separate
sections 252', 254' of second conduit 246'.
[0099] Current may flow from a power source through conductor 240 of first
conduit 246 to
section 252. The current may flow through hydrocarbon containing layer 212 to
section 254'
of second conduit 246'. The current may return to the power source through
conductor 240'
of second conduit 246'. Similarly, current may flow through conductor 240 of
second conduit
246' to section 252', through hydrocarbon layer 212 to section 254 of first
conduit 246, and
the current may return to the power source through conductor 240' of the first
conduit 246.
Current flow is indicated by arrows 244. Generation of current flow from
electrically
21
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
conductive sections of conduits 246, 246' may heat portions of hydrocarbon
layer 212
between the conduits and create fluid injectivity in the layer, mobilize
hydrocarbons in the
layer, and/or pyrolyze hydrocarbons in the layer. In some embodiments, one or
more portions
of conduits 246, 246' are positioned in shale layers.
[0100] By creating opposite current flow through the wellbores, as described
with reference to
FIGS. 3 and 4, magnetic fields in the overburden may cancel out. Cancellation
of the
magnetic fields in the overburden may allow ferromagnetic materials to be used
in overburden
casings 216. Using ferromagnetic casings in the wellbores may be less
expensive and/or
easier to install than non-ferromagnetic casings (such as fiberglass casings).
[0101] In some embodiments, two or more conduits may branch from a common
wellbore.
FIG. 5 depicts a schematic of an embodiment of two conduits extending from one
common
wellbore. Extending the conduits from one common wellbore may reduce costs by
forming
fewer wellbores in the formation. Using common wellbores may allow wellbores
to be spaced
further apart and produce the same heating efficiencies and the same heating
times as drilling
two different wellbores for each conduit through the formation. Using common
wellbores
may allow ferromagnetic materials to be used in overburden casing 216 since
the magnetic
fields cancel due to the approximately equal and opposite flow of current in
the overburden
section of conduits 230, 232. Extending conduits from one common wellbore may
allow
longer conduits to be used.
[0102] Conduits 230, 232 may extend from common vertical portion 260 of
wellbore 224.
Conduit 232 may be installed through an opening (for example, a milled window)
in vertical
portion 260. Conduits 230, 232 may extend substantially horizontally or
inclined from
vertical portion 260. Conduits 230, 232 may include electrically conductive
material 236. In
some embodiments, conduits 230, 232 include electrically conductive sections
and electrically
insulating material, as described for conduit 246 in FIGS. 3 and 4. Conduit
230 and/or
conduit 232 may include openings 238. Current may flow from a power source to
conduit 230
through conductor 240. The current may pass through hydrocarbon containing
layer 212 to
conduit 232. The current may pass from conduit 232 through conductor 240' back
to the
power source to complete the circuit. The flow of current as shown by arrows
244 through
hydrocarbon layer 212 from conduits 230, 232 heats the hydrocarbon layer
between the
conduits.
22
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0103] In certain embodiments, electrodes (such as conduits 230, 232, conduit
246, and/or
ground 248) are coated or cladded with high electrical conductivity material
to reduce energy
losses. In some embodiments, overburden conductors (such as conductor 240) are
coated or
cladded with high electrical conductivity material. FIG. 7 depicts an
embodiment of conduit
230 with heating zone cladding 264 and conductor 240 with overburden cladding
266. In
certain embodiments, conduit 230 is made of carbon steel. Cladding 264 may be
copper or
another highly electrically conductive material. In certain embodiments,
cladding 264 and/or
cladding 266 is coupled to conduit 230 and/or conductor 240 by wrapping thin
layers of the
cladding onto the conduit or conductor. In some embodiments, cladding 264
and/or cladding
266 is coupled to conduit 230 and/or conductor 240 by depositing or coating
the cladding
using electrolysis.
[0104] In certain embodiments, overburden cladding 266 has a substantially
constant
thickness along the length of conductor 240 as the current along the conductor
is substantially
constant. In the hydrocarbon layer of the formation, however, electrical
current flows into the
formation and electrical current decreases linearly along the length of
conduit 230 if current
injection into the formation is uniform. Since current in conduit 230
decreases along the
length of the conduit, heating zone cladding 264 can decrease in thickness
linearly along with
the current while still reducing energy losses to acceptable levels along the
length of the
conduit. Having heating zone cladding 264 taper to a thinner thickness along
the length of
conduit 230 reduces the total cost of putting the cladding on the conduit.
[0105] The taper of heating zone cladding 264 may be selected to provide
certain electrical
output characteristics along the length of conduit 230. In certain
embodiments, the taper of
heating zone cladding 264 is designed to provide an approximately constant
current density
along the length of the conduit such that the current decreases linearly along
the length of the
conduit. In some embodiments, the thickness and taper of heating zone cladding
264 is
designed such that the formation is heated at or below a selected heating rate
(for example, at
or below about 160 W/m). In some embodiments, the thickness and taper of
heating zone
cladding 264 is designed such that a voltage gradient along the cladding is
less than a selected
value (for example, less than about 0.3 V/m).
[0106] In certain embodiments, analytical calculations may be made to optimize
the thickness
and taper of heating zone cladding 264. The thickness and taper of heating
zone cladding 264
23
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
may be optimized to produce substantial cost savings over using a heating zone
cladding of
constant thickness. For example, it may be possible reduce costs by more than
50% by
tapering heating zone cladding 264 along the length of conduit 230.
[0107] In certain embodiments, boreholes of electrodes (such as conduits 230,
232, conduit
246, and/or ground 248) are filled with an electrically conductive material
and/or a thermally
conductive material. For example, the insides of conduits may be filled with
the electrically
conductive material and/or the thermally conductive material. In certain
embodiments, the
wellbores with electrodes are filled with graphite, conductive cement, or
combinations thereof.
Filling the wellbore with electrically and/or thermally conductive material
may increase the
effective electrical diameter of the electrode for conducting current into the
formation and/or
increase distribution of any heat generated in the wellbore.
[0108] In some embodiments, a subsurface formation is heated using heating
systems
described in the embodiments depicted in FIGS. 2, 3, 4, and/or 5 to heat
fluids in hydrocarbon
layer 212 to mobilization, visbreaking, and/or pyrolyzation temperatures. Such
heated fluids
may be produced from the hydrocarbon layer and/or from other sections of the
formation. As
the hydrocarbon layer 212 is heated, the conductivity of the heated portion of
the hydrocarbon
layer increases. For example, conductivity of hydrocarbon layers close to the
surface may
increase by as much as a factor of three when the temperature of the formation
increases from
C to 100 C. For deeper layers, where the water vaporization temperature is
higher due to
20 increased fluid pressure, the increase in conductivity may be greater.
Greater increases in
conductivity may increase the heating rate of the formation. Thus, as the
conductivity
increases in the formation, increases in heating may be more concentrated in
deeper layers.
[0109] As a result of heating, the viscosity of heavy hydrocarbons in a
hydrocarbon layer is
reduced. Reducing the viscosity may create more injectivity in the layer
and/or mobilize
hydrocarbons in the layer. As a result of being able to rapidly heat the
hydrocarbon layer
using heating systems described in the embodiments depicted in FIGS. 2, 3, 4,
and/or 5,
sufficient fluid injectivity in the hydrocarbon layer may be achieved more
quickly, for
example, in about two years. In some embodiments, these heating systems are
used to create
drainage paths between the heat sources and production wells for a drive
and/or a mobilization
process. In some embodiments, these heating systems are used to provide heat
during the
24
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
drive process. The amount of heat provided by the heating systems may be small
compared to
the heat input from the drive process (for example, the heat input from steam
injection).
[0110] Once sufficient fluid injectivity has been established, a drive fluid,
a pressuring fluid,
and/or a solvation fluid may be injected in the heated portion of hydrocarbon
layer 212. In
some embodiments (for example, the embodiments depicted in FIGS. 2 and 5),
conduit 232 is
perforated and fluid is injected through the conduit to mobilize and/or
further heat
hydrocarbon layer 212. Fluids may drain and/or be mobilized towards conduit
230. Conduit
230 may be perforated at the same time as conduit 232 or perforated at the
start of production.
Formation fluids may be produced through conduit 230 and/or other sections of
the formation.
[0111] As shown in FIG. 6, conduit 230 is positioned in layer 262 located
between
hydrocarbon layers 212A and 212B. Conduit 232 is positioned in hydrocarbon
layer 212A.
Conduits 230, 232, shown in FIG. 6, may be any of conduits 230, 232, depicted
in FIGS. 2
and/or 5, as well as conduits 246, 246' or ground 248, depicted in FIGS. 3 and
4. In some
embodiments, portions of conduit 230 are positioned in hydrocarbon layers 212A
or 212B and
in layer 262.
[0112] Layer 262 may be a conductive layer, water/sand layer, or hydrocarbon
layer that has
different porosity than hydrocarbon layer 212A and/or hydrocarbon layer 212B.
In some
embodiments, layer 262 is a shale layer. Layer 262 may have conductivities
ranging from
about 0.2 mho/m to about 0.5 mho/m. Hydrocarbon layers 212A and/or 212B may
have
conductivities ranging from about 0.02 mho/m to about 0.05 mho/m. Conductivity
ratios
between layer 262 and hydrocarbon layers 212A and/or 212B may range from about
10:1,
about 20:1, or about 100:1. When layer 262 is a shale layer, heating the layer
may desiccate
the shale layer and increase the permeability of the shale layer to allow
fluid to flow through
the shale layer. The increased permeability in the shale layer allows
mobilized hydrocarbons
to flow from hydrocarbon layer 212A to hydrocarbon layer 212B, allows drive
fluids to be
injected in hydrocarbon layer 212A, and/or allows steam drive processes (for
example, SAGD,
cyclic steam soak (CSS), sequential CSS and SAGD or steam flood, or
simultaneous SAGD
and CSS) to be performed in hydrocarbon layer 212A.
[0113] In some embodiments, a conductive layer is selected to provide lateral
continuity of
conductivity within the conductive layer and to provide a substantially higher
conductivity, for
a given thickness, than the surrounding hydrocarbon layers. Thin conductive
layers selected
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
on this basis may substantially confine the heat generation within and around
the conductive
layers and allow much greater spacing between rows of electrodes. In some
embodiments,
layers to be heated are selected, on the basis of resistivity well logs, to
provide lateral
continuity of conductivity. Selection of layers to be heated is described in
U.S. Patent No.
4,926,941 to Glandt et al.
[0114] Once sufficient fluid injectivity is created, fluid may be injected in
layer 262 through
an injection well and/or conduit 230 to heat or mobilize fluids in hydrocarbon
layer 212B.
Fluids may be produced from hydrocarbon layer 212B and/or other sections of
the formation.
In some embodiments, fluid is injected in conduit 232 to mobilize and/or heat
in hydrocarbon
layer 212A. Heated and/or mobilized fluids may be produced from conduit 230
and/or other
production wells located in hydrocarbon layer 212B and/or other sections of
the formation.
[0115] In certain embodiments, a solvation fluid, in combination with a
pressurizing fluid, is
used to treat the hydrocarbon formation in addition to the in situ heat
treatment process. In
some embodiments, the solvation fluid, in combination with the pressurizing
fluid, is used
after the hydrocarbon formation has been treated using a drive process. In
some embodiments,
solvation fluids are foamed or made into foams to improve the efficiency of
the drive process.
Since an effective viscosity of the foam may be greater than the viscosity of
the individual
components, the use of a foaming composition may improve the sweep efficiency
of the drive
fluid.
[0116] In some embodiments, the solvation fluid includes a foaming
composition. The
foaming composition may be injected simultaneously or alternately with the
pressurizing fluid
and/or the drive fluid to form foam in the heated section. Use of foaming
compositions may
be more advantageous than use of polymer solutions since foaming compositions
are
thermally stable at temperatures up to 600 C while polymer compositions may
degrade at
temperatures above 150 C. Use of foaming compositions at temperatures above
about 150 C
may allow more hydrocarbon fluids and/or more efficient removal of
hydrocarbons from the
formation as compared to use of polymer compositions.
[0117] Foaming compositions may include, but are not limited to, surfactants.
In certain
embodiments, the foaming composition includes a polymer, a surfactant, an
inorganic base,
water, steam, and/or brine. The inorganic base may include, but is not limited
to, sodium
hydroxide, potassium hydroxide, potassium carbonate, potassium bicarbonate,
sodium
26
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
carbonate, sodium bicarbonate, or mixtures thereof. Polymers include polymers
soluble in
water or brine such as, but not limited to, ethylene oxide or propylene oxide
polymers.
[0118] Surfactants include ionic surfactants and/or nonionic surfactants.
Examples of ionic
surfactants include alpha-olefinic sulfonates, alkyl sodium sulfonates, and
sodium alkyl
benzene sulfonates. Non-ionic surfactants include, for example,
triethanolamine. Surfactants
capable of forming foams include, but are not limited to, alpha-olefinic
sulfonates,
alkylpolyalkoxyalkylene sulfonates, aromatic sulfonates, alkyl aromatic
sulfonates, alcohol
ethoxy glycerol sulfonates (AEGS), or mixtures thereof. Non-limiting examples
of surfactants
capable of being foamed include AEGS 25-12 surfactant, sodium dodecyl 3EO
sulfate, and
sulfates made from branched alcohols made using the Guerbet method such as,
for example,
sodium dodecyl (Guerbert) 3PO sulfate63, ammonium isotridecyl(Guerbert) 4PO
sulfate63
sodium tetradecyl (Guerbert) 4PO sulfate63. Nonionic and ionic surfactants
and/or methods of
use and/or methods of foaming for treating a hydrocarbon formation are
described in U.S.
Patent Nos. 4,643,256 to Dilgren et al.; 5,193,618 to Loh et al.; 5,046,560 to
Teletzke et al.;
5,358,045 to Sevigny et al.; 6,439,308 to Wang; 7,055,602 to Shpakoff et al.;
7,137,447 to
Shpakoff et al.; 7,229,950 to Shpakoff et al.; and 7,262,153 to Shpakoff et
al.; and by
Wellington et al., in "Surfactant-Induced Mobility Control for Carbon Dioxide
Studied with
Computerized Tomography," American Chemical Society Symposium Series No. 373,
1988.
[0119] Foam may be formed in the formation by injecting the foaming
composition during or
after addition of steam. Pressurizing fluid (for example, carbon dioxide,
methane, and/or
nitrogen) may be injected in the formation before, during, or after the
foaming composition is
injected. A type of pressurizing fluid may be based on the surfactant used in
the foaming
composition. For example, carbon dioxide may be used with alcohol ethoxy
glycerol
sulfonates. The pressurizing fluid and foaming composition may mix in the
formation and
produce foam. In some embodiments, non-condensable gas is mixed with the
foaming
composition prior to injection to form a pre-foamed composition. The foaming
composition,
the pressurizing fluid, and/or the pre-foamed composition may be periodically
injected in the
heated formation. The foaming composition, pre-foamed compositions, drive
fluids, and/or
pressurizing fluids may be injected at a pressure sufficient to displace the
formation fluids
without fracturing the reservoir.
27
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0120] FIG. 8 depicts an embodiment of a u-shaped heater that has an
inductively energized
tubular. Heater 222 includes electrical conductor 220 and tubular 226 in an
opening that
spans between wellbore 224A and wellbore 224B. In certain embodiments,
electrical
conductor 220 and/or the current carrying portion of the electrical conductor
is electrically
insulated from tubular 226. Electrical conductor 220 and/or the current
carrying portion of the
electrical conductor is electrically insulated from tubular 226 such that
electrical current does
not flow from the electrical conductor to the tubular, or vice versa (for
example, the tubular is
not electrically connected to the electrical conductor).
[0121] In some embodiments, electrical conductor 220 is centralized inside
tubular 226 (for
example, using centralizers 214 or other support structures, as shown in FIG.
9). Centralizers
214 may electrically insulate electrical conductor 220 from tubular 226. In
some
embodiments, tubular 226 contacts electrical conductor 220. For example,
tubular 226 may
hang, drape, or otherwise touch electrical conductor 220. In some embodiments,
electrical
conductor 220 includes electrical insulation (for example, magnesium oxide or
porcelain
enamel) that insulates the current carrying portion of the electrical
conductor from tubular
226. The electrical insulation inhibits current from flowing between the
current carrying
portion of electrical conductor 220 and tubular 226 if the electrical
conductor and the tubular
are in physical contact with each other.
[0122] In some embodiments, electrical conductor 220 is an exposed metal
conductor heater
or a conductor-in-conduit heater. In certain embodiments, electrical conductor
220 is an
insulated conductor such as a mineral insulated conductor. The insulated
conductor may have
a copper core, copper alloy core, or a similar electrically conductive, low
resistance core that
has low electrical losses. In some embodiments, the core is a copper core with
a diameter
between about 0.5" (1.27 cm) and about 1" (2.54 cm). The sheath or jacket of
the insulated
conductor may be a non-ferromagnetic, corrosion resistant steel such as 347
stainless steel,
625 stainless steel, 825 stainless steel, 304 stainless steel, or copper with
a protective layer (for
example, a protective cladding). The sheath may have an outer diameter of
between about 1"
(2.54 cm) and about 1.25" (3.18 cm).
[0123] In some embodiments, the sheath or jacket of the insulated conductor is
in physical
contact with the tubular 226 (for example, the tubular is in physical contact
with the sheath
along the length of the tubular) or the sheath is electrically connected to
the tubular. In such
28
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
embodiments, the electrical insulation of the insulated conductor electrically
insulates the core
of the insulated conductor from the jacket and the tubular. FIG. 10 depicts an
embodiment of
an induction heater with the sheath of an insulated conductor in electrical
contact with tubular
226. Electrical conductor 220 is the insulated conductor. The sheath of the
insulated
conductor is electrically connected to tubular 226 using electrical contactors
268. In some
embodiments, electrical contactors 268 are sliding contactors. In certain
embodiments,
electrical contactors 268 electrically connect the sheath of the insulated
conductor to tubular
226 at or near the ends of the tubular. Electrically connecting at or near the
ends of tubular
226 substantially equalizes the voltage along the tubular with the voltage
along the sheath of
the insulated conductor. Equalizing the voltages along tubular 226 and along
the sheath may
inhibit arcing between the tubular and the sheath.
[0124] Tubular 226, shown in FIGS. 8, 9, and 10, may be ferromagnetic or
include
ferromagnetic materials. Tubular 226 may have a thickness such that when
electrical
conductor 220 is energized with time-varying current, the electrical conductor
induces
electrical current flow on the surfaces of tubular 226 due to the
ferromagnetic properties of the
tubular (for example, current flow is induced on both the inside of the
tubular and the outside
of the tubular). Current flow is induced in the skin depth of the surfaces of
tubular 226 so that
the tubular operates as a skin effect heater. In certain embodiments, the
induced current
circulates axially (longitudinally) on the inside and/or outside surfaces of
tubular 226.
Longitudinal flow of current through electrical conductor 220 induces
primarily longitudinal
current flow in tubular 226 (the majority of the induced current flow is in
the longitudinal
direction in the tubular). Having primarily longitudinal induced current flow
in tubular 226
may provide a higher resistance per foot than if the induced current flow is
primarily angular
current flow.
[0125] In certain embodiments, current flow in tubular 226 is induced with low
frequency
current in electrical conductor 220 (for example, from 50 Hz or 60 Hz up to
about 1000 Hz).
In some embodiments, induced currents on the inside and outside surfaces of
tubular 226 are
substantially equal.
[0126] In certain embodiments, tubular 226 has a thickness that is greater
than the skin depth
of the ferromagnetic material in the tubular at or near the Curie temperature
of the
ferromagnetic material or at or near the phase transformation temperature of
the ferromagnetic
29
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
material. For example, tubular 226 may have a thickness of at least 2.1, at
least 2.5 times, at
least 3 times, or at least 4 times the skin depth of the ferromagnetic
material in the tubular near
the Curie temperature or the phase transformation temperature of the
ferromagnetic material.
In certain embodiments, tubular 226 has a thickness of at least 2.1 times, at
least 2.5 times, at
least 3 times, or at least 4 times the skin depth of the ferromagnetic
material in the tubular at
about 50 C below the Curie temperature or the phase transformation
temperature of the
ferromagnetic material.
[0127] In certain embodiments, tubular 226 is carbon steel. In some
embodiments, tubular
226 is coated with a corrosion resistant coating (for example, porcelain or
ceramic coating)
and/or an electrically insulating coating. In some embodiments, electrical
conductor 220 has
an electrically insulating coating. Examples of the electrically insulating
coating on tubular
226 and/or electrical conductor 220 include, but are not limited to, a
porcelain enamel coating,
alumina coating, or alumina-titania coating. In some embodiments, tubular 226
and/or
electrical conductor 220 are coated with a coating such as polyethylene or
another suitable low
friction coefficient coating that may melt or decompose when the heater is
energized. The
coating may facilitate placement of the tubular and/or the electrical
conductor in the
formation.
[0128] In some embodiments, tubular 226 includes corrosion resistant
ferromagnetic material
such as, but not limited to, 410 stainless steel, 446 stainless steel, T/P91
stainless steel, T/P92
stainless steel, alloy 52, alloy 42, and Invar 36. In some embodiments,
tubular 226 is a
stainless steel tubular with cobalt added (for example, between about 3% by
weight and about
10% by weight cobalt added) and/or molybdenum (for example, about 0.5 %
molybdenum by
weight).
[0129] At or near the Curie temperature or the phase transformation
temperature of the
ferromagnetic material in tubular 226, the magnetic permeability of the
ferromagnetic material
decreases rapidly. When the magnetic permeability of tubular 226 decreases at
or near the
Curie temperature or the phase transformation temperature, there is little or
no current flow in
the tubular because, at these temperatures, the tubular is essentially non-
ferromagnetic and
electrical conductor 220 is unable to induce current flow or substantial
current flow in the
tubular. With little or no current flow in tubular 226, the temperature of the
tubular will drop
to lower temperatures until the magnetic permeability increases and the
tubular becomes
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
ferromagnetic again. Thus, tubular 226 self-limits at or near the Curie
temperature or the
phase transformation temperature and operates as a temperature limited heater
due to the
ferromagnetic properties of the ferromagnetic material in the tubular. Because
current is
induced in tubular 226, the turndown ratio may be higher and the drop in
current sharper for
the tubular than for temperature limited heaters that apply current directly
to the ferromagnetic
material. For example, heaters with current induced in tubular 226 may have
turndown ratios
of at least about 5, at least about 10, or at least about 20 while temperature
limited heaters that
apply current directly to the ferromagnetic material may have turndown ratios
that are at most
about 5.
[0130] When current is induced in tubular 226, the tubular provides heat to
hydrocarbon layer
212 and defines the heating zone in the hydrocarbon layer. In certain
embodiments, tubular
226 heats to temperatures of at least about 300 C, at least about 500 C, or
at least about 700
C. Because current is induced on both the inside and outside surfaces of
tubular 226, the heat
generation of the tubular is increased as compared to temperature limited
heaters that have
current directly applied to the ferromagnetic material and current flow is
limited to one
surface. Thus, less current may be provided to electrical conductor 220 to
generate the same
heat as heaters that apply current directly to the ferromagnetic material.
Using less current in
electrical conductor 220 decreases power consumption and reduces power losses
in the
overburden of the formation.
[0131] In certain embodiments, tubulars 226 have large diameters. The large
diameters may
be used to equalize or substantially equalize high pressures on the tubular
from either the
inside or the outside of the tubular. In some embodiments, tubular 226 has a
diameter in a
range between about 1.5" (about 3.8 cm) and about 5" (about 12.7 cm). In some
embodiments, tubular 226 has a diameter in a range between about 3 cm and
about 13 cm,
between about 4 cm and about 12 cm, or between about 5 cm and about 11 cm.
Increasing the
diameter of tubular 226 may provide more heat output to the formation by
increasing the heat
transfer surface area of the tubular.
[0132] In some embodiments, fluids flow through the annulus of tubular 226 or
through
another conduit inside the tubular. The fluids may be used, for example, to
cool down the
heater, to recover heat from the heater, and/or to initially heat the
formation before energizing
the heater.
31
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
[0133] In some embodiments, a method for heating a hydrocarbon containing
formation may
include providing a time-varying electrical current at a first frequency to an
elongated
electrical conductor located in the formation using an inductive heater.
Electrical current flow
may be induced in a ferromagnetic conductor with the time-varying electrical
current at the
first frequency. In some embodiments, the ferromagnetic conductor may at least
partially
surround and at least partially extend lengthwise around the electrical
conductor. The
ferromagnetic conductor may be resistively heated with the induced electrical
current flow.
For example, the ferromagnetic conductor may be resistively heated with the
induced
electrical current flow such that the ferromagnetic conductor resistively
heats up to a first
temperature. The first temperature may be at most about 300 C. Heat may be
allowed to
transfer from the ferromagnetic conductor at the first temperature to at least
a part of the
formation. At least some water in the formation may be vaporized with the
ferromagnetic
conductor at the first temperature. At these lower temperatures (for example,
up to about 260
C or about 300 C) coke may be inhibited from forming without inducing heater
damage.
[0134] In some embodiments, the time-varying electrical current may be
provided at a second
frequency to the elongated electrical conductor. Electrical current flow may
be induced in the
ferromagnetic conductor with the time-varying electrical current at the second
frequency. The
ferromagnetic conductor may be resistively heated with the induced electrical
current flow.
For example, the ferromagnetic conductor may be resistively heated with the
induced
electrical current flow such that the ferromagnetic conductor resistively
heats up to a second
temperature. The second temperature may be above about 300 C. Heat may be
allowed to
transfer from the ferromagnetic conductor at the second temperature to at
least a part of the
formation. At least some hydrocarbons in the part of the formation may be
mobilized with the
ferromagnetic conductor at the second temperature. Caution must be taken with
the second
frequency, in that it must not be raised too high or the inductive heater may
be damaged. In
some embodiments, a multiple frequency low temperature inductive heater may be
provided
by Siemens AG (Munich, Germany).
[0135] It is to be understood the invention is not limited to particular
systems described which
may, of course, vary. It is also to be understood that the terminology used
herein is for the
purpose of describing particular embodiments only, and is not intended to be
limiting. As
used in this specification, the singular forms "a", "an" and "the" include
plural referents unless
32
CA 02792275 2012-09-05
WO 2011/127262 PCT/US2011/031549
TH4018-PCT
the content clearly indicates otherwise. Thus, for example, reference to "a
core" includes a
combination of two or more cores and reference to "a material" includes
mixtures of
materials.
[0136] Further modifications and alternative embodiments of various aspects of
the invention
will be apparent to those skilled in the art in view of this description.
Accordingly, this
description is to be construed as illustrative only and is for the purpose of
teaching those
skilled in the art the general manner of carrying out the invention. It is to
be understood that
the forms of the invention shown and described herein are to be taken as 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. Changes may be made in the
elements
described herein without departing from the spirit and scope of the invention
as described in
the following claims.
[0137] It is to be understood that each of the features in the claims set
forth below may be
combined with, or separated from, features from other claims. For example, the
features of
two or more dependent claims can be combined together to form a claim that is
multiply
dependent.
33
