Note: Descriptions are shown in the official language in which they were submitted.
CA 02509268 2005-06-08
METHOD OF COLLECTING HYDROCARBONS FROM TUNNELS
BACKGROUND OF THE INVENTION
Oil is a nonrenewable natural resource having great importance to the
industrialized
world. Over the past century, the consumption of oil has increased
dramatically and has become
a strategic commodity. The increased demand for and decreasing supplies of
conventional oil
has led to the development of alternative sources of crude oil such as oil
sands containing
bitumen or heavy oil and to a search for new techniques for continued recovery
of depleted
conventional oil deposits. The development of the Athabasca oil sands in
particular has resulted
in increased proven world reserves of over 170 billion barrels from the
application of surface
mining and in-situ steaming technologies.
The vast majority of the world's oil sands deposits are found in Canada and
Venezuela.
Collectively, oil sands deposits contain an estimated 6 trillion barrels of in-
place oil. In-situ
technologies which include the steam-assisted gravity drainage ("SAGD")
process are typically
applied by using horizontal drilling techniques and then injecting steam and
collecting mobilized
bitumen from these horizontal wells. It is to be understood that a reference
to bitumen herein is
intended to include heavy oil and vice versa.
Typically, wells are drilled from the earth's surface down into the oil sand
deposit and
then horizontally along the bottom of the deposit. The valuable hydrocarbons
in these oil sand
formations in their normal, undisturbed state are very viscous and immobile.
Many different
techniques have been developed to establish both a communication path through
the heavy,
highly viscous bitumen-filled sand and an efficient method to recovery the
bitumen from the
sand. These methods include such things as steam injection, solvent flooding,
gas injection, and
the like. Such processes generally involve the altering of the oil sand
formation to reduce the
viscosity of the formation, thereby allowing removal of the resource from the
formation in fluid
form by hydraulic means or gravity flow.
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To overcome the problems of conventional steam flooding, the steam-assisted
gravity
drainage ("SAGD") process was developed by professor Roger Butler and first
reduced to
practice at the Underground Test Facility ("UTF") in Alberta, Canada. This
facility involved the
construction of an access shaft through the overburden and oil sands into the
underlying
limestone. From this shaft, underground workings were developed in the
underlying limestone
from which well pairs were drilled up into the oil sands deposit and then
horizontally along the
bottom of the deposit.
The original SAGD process is based on a closely spaced pair of horizontal
wells with a
production well (producer) near the bottom of the oil sand zone and a parallel
steam injection
well (injector) located a few meters above the producer. Upon injection of
steam through the
injector ports, a steam chamber will form around and above the injector well
which will heat the
bitumen. The heated bitumen, with more mobility, and the condensed steam will
flow along the
steam chamber boundary (also called a condensation front) by gravity to the
producer. The
produced fluids are then directed to the surface for transport to refineries.
With the advent of horizontal drilling techniques, it became possible to
install SAGD
well pairs by drilling from the surface. This is now the preferred method of
implementing
SAGD. Since then, several variations of this process have since been proposed
and subjected to
limited testing. For example, a modification to SAGD has been developed
whereby the addition
of a third horizontal well has improved recovery (increased bitumen production
and decreased
steam-oil ratio) under certain operating conditions. Other variants of gravity
drain technology
include the Vapor Extraction ("VAPEX") process which involves the injection of
vaporized
solvents such as ethane or propane to create a vapor-chamber which reduces the
viscosity of the
bitumen and allows to flow downward due to gravity drainage.
The patent literature includes a number of thermal and other in-situ methods.
US
4,160,481 discloses a plurality of bore holes radially extending from a
central bore hole to inject
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steam into the oil sand formation. Steam is injected into some bore holes to
drive the oil into the
remaining bore hole where it is collected. In US 4,160,481, a method is
described in which
perforated radial tubes extend laterally into the formation from a central
bore hole. That system
uses a cyclic steam injection procedure. After a number of steam
injection/production cycles, the
process can be converted to a continuous steam drive where steam is
continuously injected into
one radial and oil is produced from another radial.
US 4,463,988, describes an in-situ recovery system for an oil sand deposit in
which a
network of horizontal production tunnels and connecting horizontal bore holes
are provided. This
is a complex structure and a difficult and expensive one to install and
operate. This invention
predates soft-ground tunneling technology and is dependent on tunnels being
driven in
competent ground such as the overburden or underlying basement rock.
US 3,386,508, describes a system for recovering oil in which a plurality of
directional
(slant) wells are drilled from the surface to intersect a central vertical
well within an oil bearing
formation. Both the directional wells and the vertical well bore communicate
fluidly with the oil
bearing formation.
In US 5,016,710, another system for recovering oil is described having a
plurality of slant
wells drilled from the surface to cooperate with a central vertical well
within an oil bearing
formation. With this design, steam may be injected into the oil bearing
formation either from the
central vertical well or from the plurality of slant wells.
Methods such as SAGD or VAPEX require a certain level of overburden for the
process
to be contained. The SAGD process is a relatively low pressure process so that
the steam
pressure will not fracture the formation and cause the steam chamber to break
down. Typically,
the SAGD process can recover 40% to 70% of the original bitumen or heavy oil
in place,
depending on the geologic complexity of the reservoir. The eventual net
recovery rate of SAGD
and other gravity drain processes is sensitive to the presence of mud and
shale layers within the
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deposits which can form barriers to the outward flow of steam and return flow
of mobilized
bitumen or heavy oil. Thus the economics of these processes are sensitive to
the complex and
variable natures of the reservoir geologies that are found.
SAGD requires that large quantities of steam be injected into the reservoir to
heat up not
only the bitumen or heavy oil but also the reservoir sand or rock matrix. The
energy required to
produce the steam is a significant fraction of the energy of the recovered
bitumen or heavy oil,
typically in the range of about 20 to about 25% of the recovered petroleum
energy. Usually the
energy source to produce the steam is natural gas. Thus the economics of the
in-situ thermal
recovery processes are sensitive to gas prices and these in-situ processes may
become
uneconomical if the price of natural gas increases substantially as occurs
from time to time
depending on weather and/or pipeline capacity.
US 6,263,965 entitled "Multiple Drain Method for Recovering Oil from Tar Sand"
describes an alternate thermal method for recovering normally immobile
hydrocarbon oil from a
subsurface oil sand deposit. The procedure comprises establishing at least one
substantially
vertical production bore hole extending from the surface of the earth to at
least the bottom of a
subsurface formation; providing a plurality of bore holes extending downwardly
from the surface
of the earth through the oil sand formation to substantially the bottom and
then substantially
horizontally at or near the bottom of the oil sand formation and converging
radially inward to
each bore hole, each radial bore hole containing a perforated or slotted tube;
continuously
injecting steam downwardly through the perforated or slotted tubes whereby the
steam
discharges through the perforations or slots and into the oil sand formation
to reduce the
viscosity of the normally immobile oil, with a substantial proportion of the
steam being injected
into the formation via the portion of each tube extending downwardly through
the oil sand
formation whereby the steam reduces the viscosity of the normally immobile oil
over an area
extending substantially between the perforated tube and the top of the oil
sand formation with
this viscosity reducing area expanding radially and moving axially inwardly
toward the vertical
production bore hole thereby creating an expanding generally conical-shaped
production
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chamber; and draining the less viscous oil and steam condensate thus obtained
downwardly by
gravity to the bottom of the production chamber and then through the
horizontal tubes into the
bottom of the vertical production bore hole for collection. One of the biggest
problems
encountered in limited field testing of single well SAGD has been plugging of
the drainage
perforations.
In recent years, there has been a dramatic increase in the number of machine
driven soft-
ground tunneling projects utilizing the proven technologies of tunneling and
tunnel boring
machines (TBMs). This increase is largely due to the technological development
of slurry and
EPB (Earth Pressure Balance) shield systems. A new generation of soft ground
tunneling
machines, markedly different from those of five years ago, now overcomes
ground conditions
that until now were too costly and impractical to undertake. This technology
enjoys a very high
safety and reliability record having been used in a variety of tunneling
applications around the
world for the last 30 years.
The civil tunneling industry has been developing soft-ground tunneling
machines for use
in a variety of transportation and infrastructure tunneling projects. For
example, a machine
manufactured in Germany measured 14.2 meters in diameter and is one of the
largest soft-ground
tunnel boring machines ever built. It was used to install a large
transportation tunnel in the
saturated clay river bottom under a river. This machine excavates by forming a
slurry ahead of
the rotating cutter head and then ingesting the slurry into a chamber held at
the local formation
pressure which, under the Elbe, reached 6 atmospheres. The entire machine is
shielded and the
men inside work at atmospheric pressure and are fully isolated from the
exterior environment.
The German machine is a mixshield machine. This machine incorporates features
of
slurry machines, Earth Pressure Balance machines, pressure shield machines and
some features
of hard rock TBMs. The small, counter-rotating cutter head in the center of
the main cutter head
was employed to overcome the sticky clays encountered under the Elbe. This
machine was
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operated within a few meters of the river bottom and control over its
positioning had to be
precise.
Soft ground tunneling machines have been used in a variety of complex and
challenging
geologic environments such as saturated clay river bottoms, gravelly, sandy,
and other mixed
geologic settings.
Currently, soft-ground tunnel liners are made of concrete and erected in
segments. The
segments may be sealed from the surrounding ground by low-cost gaskets or by
more complex
sealing arrangements if long lifetimes are required. Extruded concrete linings
are currently being
developed by the civil driven by the financial advantages of less manpower and
higher TBM
advance rates. In an extruded concrete liner, the tunnel lining is embedded in
the surrounding
ground as fluid concrete is extruded at constant pressure directly behind the
TBM supporting the
exposed surface. This method of installing concrete liners also eliminates the
need for sealing
gaskets and may provide excellent sealing at lower costs.
Hard rock tunneling machines predate soft ground machines and have been used
in most
types of rock from moderately hard to very hard (over 30,000 psi). Typically,
these machines
are easier to operate since the rock is self supporting and there is little
ground support required
behind the advancing machine.
There are many well known drilling methods for use in soft ground that is not
self
supporting. These utilize drilling bits, augurs and rotating cutter heads for
example. Typically,
soft ground drilling is carried out by a form of pipe jacking. In pipe
jacking, the pipe that
ultimately is installed is used to push the drilling bit forward providing
propulsive thrust and is
simultaneously used as the conduit for circulating the drilling mud and
cuttings. The principal
problem in drilling in soft ground is maintaining a pressure seal between the
formation and the
drilling platform. When conventional drill bits or augurs are used, this seal
is provided by the
drilling mud which may range from a slightly viscous fluid to a plasticized
drilling mud.
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Micro-tunneling is a process that uses a remotely controlled micro-tunnel
boring machine
(MTBM) combined with the pipe jacking technique to directly install
underground pipelines in a
single pass. This process avoids the need to have long stretches of open
trench for pipe laying.
In the U.S., micro-tunneling has been used to install pipe from twelve inches
to twelve feet in
diameter. Therefore, the definition for micro-tunneling in the U.S. does not
necessarily include
size and has evolved to describe a tunneling process where the workforce does
not routinely
work in the tunnel. Micro-tunneling is currently the most accurate pipeline
installation method.
Line and grade tolerances of one inch are the micro-tunneling industry
standard. This can be
extremely important when trying to install a new pipeline in an area where a
maze of
underground utility lines already exists.
Micro-tunneling was developed in the early 1970's to replace open sewers in
urban areas
with underground gravity sewers. Although originally designed for gravity
sewer construction,
this technique has since been used to install a variety of utility conduits,
underground crossings
of highways, railroads, runways, rivers, and environmentally sensitive areas
for a variety of
utilities. This process has also been used to install plant intakes and out
falls. Micro-tunneling is
also used in the pipe arch technique of supporting large underground openings
with an arch or
roof made up of small tunnels.
In micro-tunneling, sealing between the formation and the operating platform.
is
maintained by the cutting slurry at the rotating cutter head, as is practiced
in larger manned
slurry TBMs.
One of the present inventors has developed a hybrid drilling method using a
modified
pipe jacking process in conjunction with a augur cutting tool and a
plasticized drilling mud to
install horizontal wells from the bottom of a distant shaft into a river
bottom formation. This
technique was successfully used to develop water wells that receive potable
water from the river
by utilizing the river-bed as a filter for the non-potable river water.
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Existing methods for recovering oil from oil sands have numerous drawbacks.
Surface
mining techniques are typically only economical for shallow oil sands
deposits. It is common for
oil sands deposits to dip and a significant part of the ore body may be
located at depths that are
too deep to recover by surface mining methods. As a result, most of the oil
sands deposits are
unprofitable to mine. In-situ techniques are disadvantaged in that a
relatively large amount of
energy is consumed per unit energy recovered in the bitumen.
Other oil sands deposits are located under surface features that preclude the
use of surface
based recovery methods, whether by surface mining or in-situ methods. For
example, oil sands
deposits can be located under lakes, swamps, protected animal habitats and
surface mine
facilities such as tailings ponds. Estimates for economical grade bitumen in
these in-between
and inaccessible areas on the order of 30 to 100 billion barrels.
There are a number of problems associated with the SAGD process which are as
yet
unresolved. These include for example the following. Steam injection
conditions can degrade
over the length of the injection well, limiting the length of the well. The
size of the collector
wells that can be economically drilled is limited thus limiting the effective
producible length of
producer wells. The well pairs lose a substantial amount of heat to the
formation over the
lengths drilled through the overburden. There is a need to more quickly heat
the formation
laterally between laterally spaced wells. The steam chambers produced by pairs
of SAGD wells
are generally triangular in cross-section resulting in a volume of unheated
and unrecovered oil
left between the chambers in the lower part of the reservoir. Well pair
spacing is often affected
by drilling problems and the collector well cannot always be placed in the
desired relation to the
injector well.
It is an objective of the present invention in any of its embodiments to
provide a method
for installing horizontal wells suitable for SAGD and other in-situ processes
which improves the
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accuracy of horizontal well placement, provides a more effective means of
injecting steam and
recovering mobilized bitumen and reduces the surface disturbance associated
with surface
installation of horizontal wells. It is another objective to apply a these
methods to conventional
oil and gas wells to allow better drainage of reservoirs that may otherwise be
deemed depleted.
SUMMARY OF THE INVENTION
The present invention combines soft-ground tunneling and shaft sinking
technology with
proven and advanced methods of drilling wells to enable several new and
versatile methods of
implementing in-situ methods for recovery of heavy oil and bitumen from oil
sands. The present
invention can also be used in a non-thermal mode to drain pressure-depleted or
low permeability
conventional oil and gas reservoirs.
A Tunnel as a SAGD Well Pair
In a first embodiment, the present invention discloses a method and system for
recovering
bitumen and heavy oil from oil sands by using one or more tunnels emplaced
near the bottom of
the oil sand deposit by well-known, soft-ground tunnel boring machines and
tunnel liner
installation methods. Each tunnel serves as a housing for a steam injection
system and a fluid
collection system that emulates and improves on those installed by surface-
based directional
drilling techniques. As such, it is a method for locating and operating a SAGD
steam chamber
that does not require drilling well pairs from the surface such as currently
practiced for the
SAGD method in the Alberta oil sands. Further, it does not require excavation
in the underlying
hard rock basement such as done for the original SAGD underground test
facility, also in
Alberta.
The method of the present invention overcomes several problems associated with
conventional SAGD in which well pairs are installed by directional drilling
techniques controlled
from the surface. In the present invention, the location of steam injection
into the oil sand
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formation can be accurately controlled with respect to the fluid collection
points. In addition, the
steam pressure and temperature gradients associated with conventional SAGD can
be eliminated
so as to permit substantially longer horizontal injection/collection systems.
Further, fluids
(principally mobilized bitumen and condensed water) can be collected over a
larger collection
area thereby increasing production rate per unit length and brought to the
surface using well-
known pumping techniques thereby eliminating lift problems often associated
with conventional
SAGD. In another aspect of this embodiment, the method described above can be
modified and
extended to include means to inject steam at differing locations within the
oil sand deposit.
The Tunnel as a SAGD Well with Additional Drilled Wells
In a second embodiment, the method can be extended by drilling well pairs into
the oil
sands surrounding the tunnel and/or by drilling single wells into the oil
sands such as disclosed in
US 6,263,965. In yet another form of the second embodiment, the method can
extended to
include additional horizontal wells or well pairs drilled between adjacent
tunnels. This latter
embodiment allows more complete areal drainage and recovery from an oil sand
deposit
especially near the bottom of a deposit. In yet another form of the second
embodiment, tunnels
are used as locations to drill horizontal wells or well pairs and, optionally,
additional upwardly
oriented wells or well pairs into an oil sands deposit. In this second
embodiment the tunnels may
or may not be used to directly inject steam and collect fluid.
The Tunnel as a Collector
In a third embodiment, single well or well pairs may be drilled from the
surface in a
conventional manner and a lined tunnel may be used as a collector.
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The Tunnel as a Drilling Platform and Collector
To further illustrate methods of implementing in-situ methods for recovery of
heavy oil
and bitumen utilizing tunneling technology, a number of drilling variations
are described for
installing single wells, well pairs or combinations of the two utilizing
tunnels driven into the oil
sands deposits or into the underlying limestone. Tunnels installed at or near
the bottom of the oil
sands deposits are suitable for shallow deposits where formation pressures are
generally less than
about 20 bars. Tunnels installed in the underlying limestone are suitable for
deeper deposits
where formation pressures are generally greater than about 10 bars.
A preferred fourth embodiment of the present invention utilizes single wells
drilled
between tunnels and/or single wells drilled between the surface and the
tunnels. Wells drilled
between tunnels are generally approximately horizontal. Wells drilled from the
surface have a
substantial approximately horizontal portion at or near the bottom of the oil
sands deposit which
terminates at a tunnel and is connected to the tunnel.
The principle innovation of the present inventions is that wells may be
drilled from
tunnels or from the ground surface to tunnels where the tunnels are at or near
the bottom of the
reservoir or underneath the reservoir. These wells may be used to steam
bitumen or heavy oil
deposits and then drain the mobilized hydrocarbons. In the case of
conventional oil deposits, oil
may be drained by gravity to the tunnels for recovery.
In yet another form of the fourth embodiment, horizontal tunnels are used as
locations to
drill horizontal or upwardly oriented non-thermal drainage wells into
conventional oil or gas
reservoirs to effect a more complete drainage, especially of pressure-depleted
reservoirs. This
method can also be applied to conventional, low-permeability reservoirs where
the oil might be
light enough to flow downward under gravity.
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In summary, the present invention can be used as a means to install
conventional SAGD
well pairs as well as a number of known variants of in-situ thermal recovery
methods. Tunnels
can be used as platforms for drilling wells as well as locations for
collecting hydrocarbons
drained by the wells. In oil sands, these tunnel-based drilling methods may be
used from tunnels
emplaced in the oil sand deposit or in the rock formations underlying the oil
sands. When
installed directly in an oil sands deposit, one or more large lined tunnels
can themselves be used
as well pairs; as single injector/collector wells; or as platforms for
drilling wells into the oil sands
formation; or as combinations of these.
"At least one", "one or more", and "and/or" are open-ended expressions that
are both
conjunctive and disjunctive in operation. For example, each of the expressions
"at least one of
A, B and C", "at least one of A, B, or C", "one or more of A, B, and C", "one
or more of A, B, or
C" and "A, B, and/or C" means A alone, B alone, C alone, A and B together, A
and C together, B
and C together, or A, B and C together.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1, which is prior art, is a schematic representation of conventional
SAGD as currently
practiced.
Figure 2, which is prior art, is a schematic representation of how a SAGD
steam chamber drains
bitumen.
Figure 3, which is prior art, is a schematic representation of how adjacent
SAGD steam
chambers coalesce.
Figure 4 is side view of a tunnel emplaced near the bottom of an oil sands
deposit for SAGD.
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Figure 5 is and end view of multiple tunnels emplaced near the bottom of an
oil sands deposit.
Figure 6 is a plan view of multiple tunnels emplaced near the bottom of an oil
sands deposit.
Figure 7 is an isometric view of tunnel segments showing possible steam
injection and fluid
collection locations.
Figure 8 is an end view of a tunnel showing a SAGD steam chamber.
Figure 9 shows an end view of a backfilled liner around the tunnel segments.
Figure 10 is a plan view of a configuration for steam injection and
collection.
Figure 11 is an isometric view of a tunnel segment showing injector and
collector ports.
Figure 12 is a plan view of a configuration of bore holes drilled horizontally
from one or more
tunnels.
Figure 13 is an end view of a configuration of bore holes drilled from one or
more tunnels.
Figure 14 is an example of a steam chamber formed by a single
injector/collector well geometry.
Figure 15 shows an example of a slotted injector/collector pipe.
Figure 16 shows another configuration where a horizontal tunnel is used for
wells drilled from
the surface to intercept the tunnel.
Figure 17 shows an end view of an alternate method for a backfilled liner
around the tunnel
segments.
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Figure 18 is side view of a tunnel emplaced below or near the bottom of a
conventional oil or gas
reservoir for gravity drainage.
Figure 19 is a schematic end view of two tunnels in the oil sands showing all
well pairs drilled
from the tunnels.
Figure 20 is a schematic end view of two tunnels in the oil sands showing well
pairs drilled from
the tunnels and from the surface.
Figure 21 is a schematic end view of two tunnels in the oil sands showing
single wells and well
pairs drilled from the tunnels.
Figure 22 is a schematic end view of two tunnels in the oil sands showing
single wells drilled
from a tunnel and from the surface.
Figure 23 is a schematic end view of two tunnels in the limestone showing all
well pairs drilled
from the tunnels.
Figure 24 is a schematic end view of two tunnels in the limestone showing well
pairs drilled
from the tunnels and from the surface.
Figure 25 is a schematic end view of two tunnels in the limestone showing
single wells and well
pairs drilled from the tunnels.
Figure 26 is a schematic end view of two tunnels in the limestone showing
single wells drilled
from a tunnel and from the surface.
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DETAILED DESCRIPTION OF THE DRAWINGS
Figure 1, which is prior art, shows a schematic representation of a well pair
as installed
from the surface for a conventional SAGD operation as currently practiced.
Typically, the well
pair 104 and 105 are drilled from a surface pad 106 through the overburden 102
and into an oil
sand deposit 101 using directional drilling techniques. The lower well 105 is
the collector or
producer well and is generally located near the bottom of the oil sand deposit
101 just above the
underlying bedrock 103. The upper well 104 is the steam injector well and is
generally located
just above the producer well 105. The injector well 104 is typically drilled
to be parallel to the
producer well but offset 2 to 5 meters above the producer well 104 (also
referred to as a collector
well). This well pair geometry has been field tested and has confirmed the
basic operation of the
SAGD process. Steam is injected along the horizontal portion of injector 104
and rises into the
oil sand deposit, heating the oil sand and mobilizing the bitumen (mobilizing
means reducing the
viscosity to where the bitumen becomes fluid and will flow). The steam rises
and the mobilized
bitumen falls under gravity and is collected in the producer well 105. The
placement of the well
pairs horizontally not only allows the bitumen to flow downward for collection
but also presents
a long length of collector well so that commercially viable production rates
are achieved. In
practice, an oil sands deposit might be thermally produced by a number of SAGD
well pairs
ranging from about 10 well pairs to about 200 well pairs.
Figure 2, which is prior art, is a schematic representation in end view of how
a SAGD
steam chamber drains bitumen. Steam is injected 204 via an injector well 202
into the oil sands
where it heats the formation and mobilizes the bitumen as described
previously. The steam rises
206 forming a steam chamber whose leading edge 203 represents the boundary of
an interior
volume in which most of the bitumen has been displaced. The leading edge 203
of the steam
chamber steam is a region where the steam condenses, giving up its latent heat
to complete the
mobilization of the bitumen. The mobilized bitumen tends to flow downward 207
around the
leading edge 203 until it reaches the collector well 201 and is carried away
205. The pressure
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gradient between the formation and the collector well acts to cause the
bitumen to flow
downward and then inward to the collector well 201.
Figure 3, which is prior art, is a schematic representation of how adjacent
SAGD steam
chambers grow and coalesce. Multiple steam chambers such as steam chamber 303
are formed
by steam injected by several injector wells 304 shown here in end view. The
injector wells 304
are typically 3 to 10 meters above the basement rock 302 and form steam
chambers 303 that
eventually grow to the top 301 of the oil sand deposit. Figure 3 schematically
shows contours
305 which represent successive positions of the condensation surface or
leading edge of the
steam front as it advances in time and eventually coalesces with the
condensation fronts of
adjacent steam chambers.
It is one of the principal objectives of the present invention to form
multiple steam
chambers such as illustrated in Figures 2 and 3 by using soft-ground civil
tunneling techniques
rather than directional drilling techniques to install and operate one or more
injector and collector
well pairs. The method disclosed herein utilizes soft-ground tunneling
technology to form a
lined tunnel near the bottom of an oil sands deposit. In current practice,
soft-ground tunneling
machines are limited to formation fluid pressures of about 10 to 12 bars. This
limitation is
currently dictated by seal design for fluid seals on the tunnel boring machine
and can be
extended. For now,'the present invention is limited to oil sands deposits
where ambient
formation fluid pressures do not exceed about 10 bars, prior to initiating a
steam chamber. There
are many shallow deposits in the Alberta oil sands in which SAGD operations
can be applied
where formation fluid pressures are less than 10 bars. It is also possible,
using known tunneling
techniques, to locally drain fluids. If the formation is relatively
impermeable, then this can
reduce local formation fluid pressures to allow the tunneling machine to
proceed without
exceeding the pressure limits on its seals. Once the tunnel liner is
installed, higher formation
pressures can be accommodated, such as for example when steam is injected to
form a steam
chamber. Once a tunnel liner is installed, the pressure limitation can be
considerably higher than
bars as the pressure limit is now dictated by the structural integrity of the
liner and/or the
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sealing technology used to form gaskets between liner segments (unless
extruded liner
technology, which does not require gaskets, is used).
Figure 4 is side view of a tunnel 400 of diameter 408 emplaced near the bottom
of an oil
sands deposit 401. The bottom of the tunnel 400 is on or just above the
basement rock 402
which underlies the oil sand deposit 401. The overburden 403 and surface 404
are also shown.
The tunnel 400 may be formed by segments 405 which are joined together at
joints 406 during
the tunneling process. The segments 405 are preferably precast concrete
segments but may be
fabricated from other structural materials such as, for example, structural
steel or composites of
structural steel and concrete.. The segments are preferably formed from a high
temperature
concrete mix and well cured before installation. The bottom of the finished
tunnel is located as
shown by 407 on or just above the bedrock 402. If placed above the bedrock
402, the bottom of
the tunnel liner would typically be located within about 1 to 5 meters of the
bedrock 402
depending on geologic conditions such as for example a zone of high water
content lying on the
bedrock 402. The tunnel 400 is preferably formed by using a slurry or Earth
Pressure Balance
("EPB") tunnel boring machine ("TBM") and conventional tunnel liner
installation technology.
This tunneling method allows a liner to be installed while following the
desired trajectory
through the oil sand deposit 401. This trajectory may be designed to follow
the deposit which
may have been formed by a river or estuary for example. The diameter 408 of
the tunnel is
preferably in the range of about 3 meters to 5 meters. The length of the
tunnel is dependent on
the geology of the oil sand deposit 401 and may be in the approximate range of
500 meters to
10,000 meters or longer if the deposit persists or if a number of deposits are
separated by short
sections of barren ground. The tunnel 400 may be initiated from a portal
developed at the
surface or by assembling the TBM and its equipment using an access shaft
excavated from the
surface 404 through the overburden 403 to the bottom of the oil sands deposit
401. With
currently available tunneling technology, a tunnel liner can be installed to
within a few
millimeters of its desired design location. This therefore places a lower
limit on the accuracy of
placement of steam injection and fluid collection points that is considerably
more precise than is
currently possible with horizontal drilling methods operated from the ground
surface 404.
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Figure 5 is and end view of multiple tunnels 505 emplaced near the bottom of
an oil
sands deposit 501. Figure 5 shows the surface 504, the overburden 503, the oil
sand deposit 501
and the underlying basement rock 502. Each tunnel 505 is designed to provide a
well-pair
equivalent to that of a conventional SAGD well pair installed by directional
drilling from the
surface 504. The tunnels 505 are driven roughly parallel to each other with a
spacing 506. The
spacing 506 between adjacent tunnels 505 is typically in the range of about 50
to about 200
meters. This spacing is the same or slightly larger than that of typical of
SAGD well pairs
installed in current SAGD operations. The tunnel is formed by a structural
liner 509 which is
preferably constructed of approximately cylindrical segments that are gasketed
and bolted
together. Steam is injected at locations 507 along or near the top of the
tunnel liner 509 and
fluids are collected through openings 508 along both sides of the bottom half
of the tunnel liner
509 or even through a single collection port (not shown) at the bottom of the
tunnel liner 509.
Thus steam is injected at a controlled height above the collectors 508.
Because of the diameter
of the tunnel, which is preferably in the range of about 3 meters to 5 meters,
the collector area is
substantially greater than the area of the collector well used in conventional
SAGD.
Figure 6 is a plan view of multiple tunnels 601 emplaced near the bottom of an
oil sands
deposit. Each tunnel acts as a conventional SAGD well pair and consequently
the spacing
between adjacent tunnels will be similar to that used when installing adjacent
SAGD well pairs.
Each tunnel will therefore be capable of heating and draining a width 603 of
oil sand deposit on
either side that is comparable to that of conventional SAGD well pairs. As
described in Figure 5,
the spacing between adjacent tunnels is typically in the range of about 50 to
about 200 meters.
Therefore the width 603 of the region heated and drained by on either side of
each tunnel will
also be approximately in the range of about 50 to about 200 meters. The exact
width of the
lateral spacing is determined by the geology of the oil sand deposit, prior
experience with
conventional SAGD operations in similar deposits and experience with the
present invention
which may permit wider spacing because of its better recovery capability. The
spacing between
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adjacent SAGD tunnels could be increased substantially if other more effective
methods of
mobilizing the bitumen are developed and field proven.
Figure 7 is an isometric view of a tunnel 700 formed by segments 701 showing
possible
steam injection 702 and fluid collection 703 locations. As described in Figure
4, the length of
the tunnel 700 may be in the approximate range of 500 meters to 10,000 meters.
The length 704
of an individual tunnel liner segment 701 is typically in the approximate
range of 1 to 2 meters.
If each tunnel segment 701 has an injection port 702 and collection ports 703,
the injection of
steam 705 and the collection of fluids 706, in effect, occurs along a line
which corresponds to the
length of the tunnel 700. Thus the tunnel 700, which need not be straight but
can be sinuous as
shown in Figure 10, acts as a single long horizontal well pair such as used in
conventional
SAGD. Because the tunnel has a diameter in the range of about 3 meters to
about 5 meters, the
collection area is substantially greater than the collection area of a
collector well typically used
in conventional SAGD. Since the rate of fluid production is proportional to
the pressure and
gravity gradients and to the natural logarithm of the effective diameter of
the collector, the
production rate per unit length of the present invention should be higher by a
factor of about 2 or
3 than the production rate of a conventional SAGD collector well. One of a
number of alternate
methods of forming injection and collection ports is discussed later in Figure
11.
Figure 8 is an end view of a tunnel as represented by a tunnel liner 806
showing a SAGD
steam chamber as represented by its outwardly moving condensation front 805.
Figure 8 also
shows the surface 802, the overburden 803, the oil sand deposit 801 and the
underlying basement
rock 804. The steam chamber is formed by steam injected through ports 807
spaced along the
top of the tunnel liner 806 as described in Figure 7. The fluids which are
comprised of mobilized
bitumen and condensed steam, drain around the periphery 805 of the steam
chamber and are
collected through the collector ports 808 spaced along either or both sides of
the bottom half of
the tunnel liner 806 as also described in Figure 7. Since the characteristic
size of a fully
developed steam chamber is on the order of the thickness of the oil sand
deposit 801, the
collectors 808 are effectively along a line located at precise vertical and
horizontal distances
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CA 02509268 2005-06-08
from the line formed by the injectors 807. This geometry is therefore, in
effect, a steam injection
well with a large collector well spaced appropriately beneath the injector
well.
Figure 9 shows a side view of a backfilled tunnel liner 904 around a tunnel
segments and
illustrates many of the unique features of the present invention. An end view
of a tunnel 900 is
shown here embedded in an oil sands deposit 901 just above the underlying
basement rock 902.
A tunnel structural liner 904 provides ground support for an excavated bore
903. The liner 904
is preferably fabricated well before installation (so as to properly cure the
high temperature
concrete) using a high-strength, high-temperature concrete to form short liner
segments that can
be installed, gasketed and bolted together as part of the tunneling process.
There are several
well-known high temperature concretes available that (a) incorporate additives
such as, for
example, silica fume and high-range, water-reducing admixtures and (b) that
can be mixed and
cured well in advance of installation by procedures known to promote good
structural
performance at high temperatures in the range of approximately 200C to 400C.
The excavated
bore and tunnel liner installation are preferably implemented using a soft-
ground tunnel boring
machine and well-known liner segment installation techniques. The annular
space 905 between
the liner 904 and the inner surface of the excavated bore 903 is backfilled
with a low-cost,
readily available material such as, for example, pea gravel, coarse sand,
small rocks and/or the
like or combinations of these materials. For a liner diameter in the range of
about 3 meters to
about 5 meters, the annular gap 905 is preferably in the range of about 25 mm
to about 300 mm
wide. The material in the annular space 905 serves a number of important
functions. It isolates
the liner 904 from direct contact with the oil sand; it provides a thermal
barrier to heat transfer to
the liner 904 from the heated oil sand 901; it provides a filtering action or
screen to prevent oil
sands material from plugging injector and collector ports; and it provides a
highly permeable
pathway to allow the fluids to more readily drain downward and flow to the
collection ports 909.
In this figure, steam is piped down the tunnel 900 and a portion is injected
at each injection port
907. The steam pipes may be wrapped with a common insulating material to
minimize heat loss
before injection into the formation. This is a significant advantage that the
present invention has
over SAGD using well pairs drilled from the surface. An injection port or
ports 907 are located
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preferably in at least every tunnel liner segment as shown for example in
Figure 7. The steam
injection port 907 can inject the steam at the outside surface of the liner
904 or more preferably
just beyond the annular layer 905 directly into the oil sand 901 as shown in
the present figure.
Since the steam, generated on the surface or in the tunnel itself, is
transported from its point of
origin down the inside of the tunnel liner 904 by a piping system 906, its
pressure and
temperature can be readily monitored. If the steam conditions degrade with
length down the
tunnel, they can be returned to their desired levels by heater and compressor
apparatuses located
at intervals along the tunnel. This later capability is an important advantage
over injector wells
installed by directional drilling and allows the tunnel-based steam injection
system to be as long
as required by the oil sands deposit being drained. The fluids are collected
through ports 909
located near the bottom of the tunnel. In this figure, two ports are shown at
each cross-sectional
location, although there may be any number of ports from one to many at each
cross-sectional
location. Along the length of the tunnel 900, collection ports 909 are located
preferably in at
least every tunnel liner segment as shown for example in Figure 7. The
collection ports 909 feed
into a piping system 908 which allows the collected fluids to be transported
through the tunnel
and to the surface for further processing. As with the steam injection system,
the pumping
pressure of the collected fluids can be boosted at intervals along the tunnel
and can be further
boosted, if necessary, to transport the collected fluids up an access shaft to
the surface. This later
capability is another important advantage over collector wells installed by
directional drilling
from the surface and avoids all of the lifting problems often associated with
collector wells as
used in currently practiced SAGD operations. In addition, the collector ports
can be larger in
area than those of a collector well typically installed by directional
drilling. Large collector ports
can still be covered with screens to prevent entry of sand from the
surrounding deposit. This is
an advantage that minimizes or reduces clogging of the collector ports which
is known to occur
in conventional SAGD operations. It is also possible to create a partial
vacuum at the fluid
collection ports 909 to increase the pressure gradient between the formation
901 and the
collection piping system 908 by installing vacuum pumps in the tunnel near the
collection points.
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Figure 10 is a plan view of yet another alternate configuration for steam
injection and
collection. As described in Figure 4 for example, approximately parallel SAGD
tunnels may be
installed while following a sinuous trajectory through the oil sand deposit
such as may have been
formed by a river or estuary. Figure 10 illustrates three approximately
parallel tunnels 1201 that
follow a hypothetical fluvial oil sand deposit. These tunnels may have their
own steam injector
and fluid collections systems similar to those depicted in Figures 4 through 9
for example. In
addition, this figure shows horizontal connector wells or well pairs 1202
installed between
adjacent tunnels 1201. These wells or well pairs may be installed by known
drilling techniques
operated from within the tunnels 1201. If well pairs are used to connect the
tunnels 1201, steam
may be injected by the upper well and fluids collected by the lower well as in
conventional
SAGD. The tunnels 1201 act as accessible locations for drilling SAGD well
pairs from
underground and as locations where steam can be provided and fluids collected
for transport to
the surface. Alternately, a single well 1202 can be drilled between tunnels
1201 wherein the
single well serves as both a steam injector and fluid collector. Again, the
tunnels 1201 act as
accessible locations for drilling the connector well from underground and as
locations where
steam can be provided and fluids collected for transport to the surface. The
connecting pipes
1202 are preferably in the diameter range of about 75 mm to about 700 mm. The
lengths of the
connecting pipes 1202 are determined by the separation of the tunnels 1201
which, as described
previously are typically in the range of about 50 to about 1,000 meters.
In Figure 7, for example, injector and collector ports were shown as being
circular holes.
These ports can be in the range of 100 mm to 400 mm in diameter. Alternately,
as discussed in
the following figure, the injection and collection ports can be made as long
slots that can be
almost as long as the tunnel liner segments but, if necessary, substantially
wider than the slots
used in conventional SAGD well pairs.
Figure 11 is an isometric view of a tunnel segment 1301 showing an example of
a
possible layout for slotted injector and collector ports. In SAGD as currently
practiced, the
injector well is typically made from a steel tubing with long narrow slots
formed into the tubing
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wall. The slots are approximately 150 mm long and 0.3 mm wide. The narrow
width of these
slots is dictated by the requirement to prevent sand from entering into the
slot when steam is not
being injected. In SAGD as currently practiced, the collector well is also
typically made from
steel tubing with long narrow slots approximately 150 mm long and 0.3 mm wide,
also to
prevent sand from entering into the slot as hot fluids (principally mobilized
bitumen and
condensed steam) are collected. An injector port 1302 of the present invention
is shown on top
of the tunnel segment 1301. The injector port 1302 is a long slot through
which steam is injected
into the formation. The slot can be made during the fabrication of the tunnel
liner segment 1301.
It can be covered by a screen or screens that allow steam to be injected while
sand is prevented
from entering the slot when steam is not being injected. The screen mesh is of
a size that allows
as much or more injection area while having openings approximately in the
range of the slot
widths used in conventional SAGD well pipe. The collector ports 1303 and 1304
can be made in
the same way as the injector port 1302. The injector port 1302 is typically
placed at or near the
top of the segment 1301. One of more collector ports are typically located in
the bottom half of
the segment 1301 as shown for example by the location of ports 1303 and 1304.
The
circumferential strength of the liner segment 1301 can be maintained for
example by embedding
reinforcing bar in the concrete liners across the ports in the circumferential
direction.
Figure 12 is a plan view of a configuration of horizontal wells drilled or
installed from
one or more tunnels wherein the tunnels themselves may or may not also contain
provisions for
directly injecting steam and collecting fluids. As shown in Figure 12, one or
more tunnels 1401
are driven substantially horizontally at or near the bottom of the oil sand
deposit, approximately
following the path of interest in the formation. If more than one tunnel is
installed, then the
tunnels are spaced approximately equally by a distance 1402 which is in the
range of
approximately 200 to 1,000 meters. In this embodiment, a plurality of
horizontal wells 1403 are
drilled outwardly from each tunnel 1401 through the oil sand formation. These
boreholes are
drilled from the tunnel and are designed to remain substantially within the
oil sand deposit and
are positioned substantially horizontally at or near the bottom of the oil
sands deposit. Each bore
hole 1403 contains a perforated or slotted tube for injecting steam and
collecting mobilized
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fluids. The steam discharges through the perforations or slots and into the
oil sand formation
whereby the steam reduces the viscosity of the normally immobile bitumen over
an area
extending substantially between the perforated tube and the top of the oil
sand formation with
this viscosity reducing area expanding upward thereby creating an expanding
generally conical-
shaped production chamber as viewed from the end of the borehole such as
depicted for example
in Figure 14. The less viscous oil and steam condensate and drain downwardly
by gravity to the
bottom of the steam chamber and then through the horizontal tubes into the
tunnel for collection
and removal to a processing facility. As shown in Figure 12, the horizontal
wells 1403 are
drilled from the tunnel 1401 and terminate in the oil sand formation. The
length of the horizontal
wells 1403 are approximately half the distance between adjacent tunnels. The
lengths of the
horizontal wells 1403 are thus preferably in the approximate range of about
100 to about 400
meters. The horizontal wells 1403 may be drilled from any location along the
length of the
tunnels 1401 but are typically spaced in the range of approximately 50 to
approximately 150
meters apart as shown by range 1405. Horizontal wells originating from
adjacent tunnels may or
may not overlap in lateral extent as shown by examples 1410 (non-overlapping)
and
1411 (overlapping). It is obvious that this deployment of drilled horizontal
wells may also be
used in conjunction with the injection and collection methods applied within
the tunnels
themselves as shown for example in Figures 7 through 9. It is also obvious
that the horizontal
wells can be drilled as pairs with one well above the other to form a well
pair such as used in
SAGD operations where the well pairs are drilled from the surface such as
shown in Figure 1.
Figure 13 is an end view of a configuration of horizontal wells originating
from one or
more tunnels 1501. Horizontal wells 1502 may be drilled substantially
horizontally near or at the
bottom of the oil sand deposit 1511 just above the basement rock 1510 and can
be operated as
steam injectors only or as injection/collector wells.
Figure 14 is an example of a steam chamber formed in an oil sands deposit 1603
by a
single wellbore. This figure shows and end view of a steam chamber 1601 whose
condensation
front 1602 expands outwardly into the oil sands 1603. Steam is injected 1604
and fluids are
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CA 02509268 2005-06-08
collected 1605 through slots or perforations in a single well pipe 1606
located at or just above
the basement rock 1610.
Figure 15 shows an example of a perforated and/or slotted injector/collector
pipe
1701 such as described in US 6,263, 965 entitled "Multiple Drain Method for
Recovering Oil
from Tar Sand". The casing or pipe 1701 is installed in an oil sands deposit
1705 from a tunnel
1706. The pipe 1701 has slots and /or perforations 1702 through which steam is
injected and
fluids are collected simultaneously. The steam and fluids collected by the
pipes 1701 are
transported inside the tunnel by a system of other connected pipes represented
here as 1704.
Figure 16 shows an example of another SAGD configuration where a horizontal
tunnel is
used in various ways and wells are drilled from the surface to intercept the
tunnel. As can be
appreciated, this method can be extended to include a plurality of tunnels and
can be combined
with any or all of the tunnel-based methods described previously. Figure 16
shows an end view
of a ground surface 1801, an interface between overburden and an oil sand
deposit 1802, an
interface between an oil sand deposit and an underlying , typically
impervious, basement rock
1803 and an oil sand deposit 1804 containing recoverable hydrocarbon,
typically bitumen or
heavy oil. A tunnel 1815 is shown installed at or near the bottom of the oil
sand deposit 1815.
As in previous discussions, the tunnel is a lined tunnel typically in the
diameter range of about 3
to 5 meters. The tunnel may be as long as required to drain a particular oil
sand deposit which is
typically a deposit laid down by an ancient fluvial or estuarine process. The
tunnel itself may be
used to inject steam and collect fluids as described for example in Figures 5
through 9. In Figure
16, a single well bore 1812 is shown where the well is drilled from the
surface 1801 to the tunnel
1815. The single well 1812 is comprised of a perforated and/or slotted tubing.
Typically, steam
is fed in from the surface 1801 and is discharged through the perforations
and/or slots and into
the oil sand formation 1804. While steam may also be injected along the
horizontal portion of
well 1812, most of the mobilized fluids (bitumen and steam condensate) is
collected through the
horizontal portion of the well 1812 and then into the tunnel 1815 where it can
be pumped to the
surface 1801 by well-known means. As described previously such as for example
in Figure 12,
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wells such as 1812 can be installed into both sides of the tunnel 1815 and
spaced along the tunnel
length any location along the length but are typically spaced in the range of
approximately 50 to
approximately 150 meters apart. The horizontal wells are preferably in the
diameter range of
about 75 mm to about 750 mm. Alternately, a pair of wells 1810 and 1811 may be
drilled from
the surface 1801 to the tunnel 1815. The well 1810 is typically used for steam
injection and the
well 1811 is typically used for collection of fluids. This is a standard SAGD
well pair
configuration but utilizes the tunnel 1815 to collect the fluids which can
then be pumped to the
surface 1801 again by well-known means. The size of the well bores and spacing
of the well
pairs along the length of the tunnel 1815 is similar to those of the single
well system of 1812. In
Figure 16, the arrows pointing away from the wells represent steam injection
and the arrows
pointing towards the wells represent fluid collection. As can be appreciated,
single well or well
pair systems can be used in combinations as dictated by field experience.
It is also possible, although not shown in the above figures, to use the
tunnels themselves
as single well systems. This can be accomplished by fabricating the tunnel
liner segments with
multiple perforations and/or slots and then injecting steam into the entire
tunnel interior. Fluids
would be collected in the bottom of the tunnel liner.
Figure 17 shows an end view of an alternate method for a backfilled liner 1904
around
the tunnel segments and illustrates a means of isolating steam from mobilized
fluids. An end
view of a tunnel is shown here embedded in an oil sands deposit 1901 just
above the underlying
basement rock 1902. A tunnel structural liner 1904 provides ground support for
an excavated
bore 1903. As described previously in Figure 9, the liner 1904 is preferably
fabricated using a
high-strength, high-temperature concrete to form short liner segments that can
be installed,
gasketed and bolted together as part of the tunneling process. The excavated
bore and tunnel
liner installation are preferably implemented using a soft-ground tunnel
boring machine and
well-known liner segment installation techniques. The annular spaces 1905,
1911 and 1912
between the liner 1904 and the inner surface of the excavated bore 1903 are
backfilled. In the
bottom portion of the annular space 1905 backfill is provided by a low cost,
readily available
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CA 02509268 2005-06-08
material such as, for example, pea gravel, coarse sand, small rocks and/or the
like or
combinations of these materials. For a liner diameter in the range of about 3
meters to about 5
meters, the annular gap 1905, 1911 and 1912 is preferably in the range of
about 25 mm to about
300 mm wide. The portion of the annular space 1911 above the previously
mentioned annular
space 1905 is thereupon backfilled with a high-temperature grout shown as a
solid grey filler.
The portion of the annular space 1912 above the previously mentioned annular
space 1911 is
then backfilled with a low cost, readily available material such as used in
annular space 1905.
The grout in annular space 1911 serves to form a seal between the filler
material in annular
spaces 1905 and 1912. This is an important feature since it is necessary to
prevent injected
steam from communicating or short-circuiting from injector ports 1907 to
collector ports 1909.
Steam may be injected through both ports 1907 and 1909 so as to heat up the
oil sand formation
surrounding the tunnel. Steam is not allowed past the grout in annular space
1911 and cannot go
around the grout because of the un-mobilized bitumen in the formation. The
steam mobilizes the
bitumen around the top and bottom portions of the tunnel. At some point, steam
injection
through ports 1909 is stopped and the mobilized bitumen is allowed to remain
in place while
steam continues to be injected through injection ports 1907. As bitumen is
drained from around
the tunnel through ports 1909, volume is created for steam to be further
injected into the
formation through ports 1907. In this figure, steam is piped down the tunnel
and a portion is
injected at each injection port 1907. The steam pipes may be wrapped with a
common
insulating material to minimize heat loss before injection into the formation.
This is a significant
advantage that the present invention has over SAGD using well pairs drilled
from the surface.
An injection port or ports 1907 are located preferably in at least every
tunnel liner segment as
shown for example in Figure 7. The steam injection port 1907 can inject the
steam at the outside
surface of the liner 1904 or more preferably just beyond the annular layer
1912 directly into the
oil sand 1901 as shown in the present figure. Since the steam, generated on
the surface or in the
tunnel itself, is transported from its point of origin down the inside of the
tunnel liner 1904 by a
piping system 1906, its pressure and temperature can be readily monitored. If
the steam
conditions degrade with length down the tunnel, they can be returned to their
desired levels by
heater and compressor apparatuses located at intervals along the tunnel. This
later capability is
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CA 02509268 2005-06-08
an important advantage over injector wells installed by directional drilling
and allows the tunnel-
based steam injection system to be as long as required by the oil sands
deposit being drained.
The fluids are collected through ports 1909 located near the bottom of the
tunnel. In this figure,
two ports are shown at each cross-sectional location, although there may be
any number of ports
from one to many at each cross-sectional location. Along the length of the
tunnel, collection
ports 1909 are located preferably in at least every tunnel liner segment as
shown for example in
Figure 7. The collection ports 1909 feed into a piping system 1908 which
allows the collected
fluids to be transported through the tunnel and to the surface for further
processing. The ability
to over cut a tunnel bore 1903, install an undersized liner 1904 and fill the
resulting annular
space with a number of different materials serving a number of functions, is
an example of how
modern tunneling technology can be used to enhance implementation of a SAGD
process.
Figure 18 is side view of a tunnel emplaced below or near the bottom of a
conventional
oil or gas reservoir for gravity drainage. In this figure, a conventional oil
or gas reservoir 2001 is
shown above a lower reservoir boundary 2002. A conventional oil or gas
reservoir is taken
herein to be a reservoir where the oil or gas is mobile and can flow in the
formation when
subjected to a pressure or gravity gradient. A tunnel 2003 may be installed,
by methods
described above for thermal gravity drain, in the formation below the
reservoir 2001 or a tunnel
2004 may be installed at or near the bottom of the reservoir 2001. In either
case, drainage wells
2006 and 2005 are drilled into the reservoir 2001 from the tunnels 2003 and
2004 respectively.
The diameters of the drainage wells, the lengths of the drainage wells and the
spacing of the
drainage wells around the tunnels and along the length of the tunnels are
similar to those
envisioned for SAGD applications. However, the lengths of the drainage wells
and the spacing
of the drainage wells along the length of the tunnels may be greater than
described previously
since the oil or gas to be drained is mobile throughout the reservoir.
There are other advantages of the present invention not discussed in the above
figures.
For example, if there is a problem during the operation of the system after
the steam chamber has
been formed, it is still possible to perform servicing and repair. The tunnel
can be strongly
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ventilated such that the tunnel air is cool and safe to work in even while the
tunnel walls remain
hot. Alternately, remotely operated robotic vehicles can be operated inside
the tunnel and
monitor or observe problem areas. When the steam chamber has completed
recovery and has
cooled down, mush of the installed equipment (piping, pumps, sumps,
diagnostics, heaters and
the like) can be retrieved from the tunnel for use in other tunnel-based SAGD
operations.
The following describes a preferred embodiment of the general approach of
combining
tunneling methods, various drilling methods and various in-situ recovery
methods in ways that
allow greater control over steam conditions and gravity drain conditions as
well as a greater
ability to effect repairs and accomplish process adjustments. The preferred
embodiment
described below also results in less surface disturbance and better working
conditions in severe
climates.
Figure 19 is a schematic end view of two tunnels 2105 in an oil sands deposit
2103
showing all well pairs 2106 and 2107 as being drilled from the tunnels 2105.
Two or more soft-
ground tunnels 2105 may be driven in an oil sands deposit 2103 which is
overlain by overburden
2102 that interfaces a ground surface 2101. The oil sands deposit 2103 is
typically underlain by
a rock formation 2104 which may be limestone for example such as is the case
for the Athabasca
oil sands in Alberta Canada. The spacing between tunnels 2105 is in the range
of approximately
200 to 1,000 meters and is dependent on, among other factors, the nature of
the deposit and the
ability of the drilling technology employed to drill the well pairs 2106 and
2107. The well pairs
2106 and 2107 are typically drilled with one well approximately over the other
well separated in
the range of 1 to 10 meters. The diameter of the individual wells is in the
diameter range of
about 75 mm to 750 mm. The approximately horizontal well pairs 2106 are
drilled from either
tunnel 2105 to intercept the adjacent tunnel 2105, the tunnels 2105 being
approximately in the
range of 200 m to 800 m apart. The diameter of the tunnels 2105 is in the
range of about 3 to 5
meters. In wide deposits, more than two approximately parallel tunnels 2105
may be used. The
approximately horizontal blind well pairs 2107 may be drilled outwards from
the tunnels 2105.
These blind well pairs 2107 are typically in the length range of approximately
100 to 500 meters
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but may be longer as blind drilling techniques are improved. If viewed from
above in plan view
such as shown in Figure 10, the spacing of well pairs along the tunnel length
is in the range of
about 50 to 150 meters. Blind well pairs 2107 and connected well pairs 2106
may or may not be
drilled from the same location along the tunnels 2105.
The methods of drilling from within the tunnels 2105 may include, for example,
conventional soft ground drilling methods using rotary or augur bits attached
to lengths of drill
pipe which are lengthened by adding additional drill pipe sections as drilling
proceeds. Drilling
methods may also include, for example, micro-tunneling techniques where a
slurry excavation
head is used and is advanced into the deposit by pipe jacking methods. Forms
of directional
drilling may be used from within a tunnel. More conventional directional
drilling methods may
be used for wells or well pairs drilled from the surface to intercept a tunnel
such as described in
subsequent discussions.
Figure 20 is a schematic end view of two tunnels 2205 in an oil sands deposit
2203
showing well pairs 2206 drilled from the tunnels and well pairs 2207 drilled
from the surface
2201 to intercept the tunnels 2205. This is an alternate method to that shown
in Figure 19 and
can result in the same approximate layout of well pairs. An advantage of the
configuration
shown in Figure 20 is that well pairs 2207 and 2206 are both accessible from
either end. The
horizontal sections of well pairs 2207 are typically in the length range of
approximately 100 to
1,000 meters but may be longer as surface drilling techniques are improved.
Otherwise, tunnel
diameters and spacing and well pair diameters and spacing are the same as
those described in
Figure 19.
Figure 21 is a schematic end view of two tunnels 2305 in an oil sands deposit
2303
showing single wells 2306 and blind well pairs 2307 drilled from the tunnels
2305. The
difference between the configuration of Figure 21 and Figure 19 is that the
wells 2306 drilled
between tunnels 2305 are single wells that can serve as both steam injectors
and mobilized
bitumen collectors. Single well injection and recovery is a less developed
technology than that
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CA 02509268 2005-06-08
based on well pairs where the lower well is typically the collector and the
upper well is typically
the injector. The major advantage of using a single well is that less drilling
is required to drain a
given reservoir volume. This can result in a significant cost reduction with
potentially no
reduction in recovery factor. Otherwise, tunnel diameters and spacing and well
pair diameters
and spacing are the same as those described in Figure 19.
Figure 22 is a schematic end view of two tunnels 2405 in an oil sands deposit
2403
showing single wells 2406 drilled from a tunnel and single wells 2407 drilled
from a location
2408 on a surface 2401 to intercept the tunnels 2405. This is an alternate
method to that shown
in Figure 23 and can result in the same general layout of wells. An advantage
of the
configuration shown in Figure 22 is that single wells 2407 and 2406 are both
accessible from
either end. The horizontal sections of wells 2407 are typically in the length
range of
approximately 100 to 1,000 meters but may be longer as surface drilling
techniques are
improved. Otherwise, tunnel diameters and spacing and well diameters and
spacing are the same
as those described in Figure 19.
Figure 23 is a schematic end view of two tunnels 2505 in, for example, a
limestone
formation 2504 showing all well pairs 2506 and 2507 drilled from the tunnels
2505. Figure 23 is
similar to Figure 19 except the tunnels 2505 are driven into an underlying
limestone formation
2504 and the well pairs 2506 and 2507 must be drilled upwards out of the
limestone 2504 and
then horizontally at or near the bottom of the oil sands 2503. The tunnel
diameters and spacing
and well pair diameters and spacing are the same as those described in Figure
19. In the case of
the blind well pairs 2507, the techniques for drilling such well pairs from
the limestone into the
oil sands has been established previously during the original development of
the SAGD method
at the Underground Test Facility ("UTF") in Alberta, Canada. In this case the
drilling of well
pairs was conducted from underground workings drilled & blasted into the
underlying limestone.
As illustrated in Figure 23, the well pairs are shown as being drilled from
tunnels bored into the
limestone. It is also possible to drill & blast small caverns at each drilling
location to provide
additional working space for the well drilling equipment. In the case of the
well pairs 2506
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CA 02509268 2005-06-08
drilled between adjacent tunnels 2505, the wells can be drilled from one
tunnel and ultimately
intercept the adjacent tunnel. This will require an innovation to presently
available drilling
technology. One way that this may be accomplished, for example, is to drill
upwards from one
tunnel out of the limestone 2504 and then horizontally at or near the bottom
of the oil sands 2503
until the horizontal well passes over the adjacent tunnel. It then is possible
to drill upwards from
the adjacent tunnel to intercept the horizontal portion of the wells 2506 in
the oil sands 2503.
The tunnels 2505 are placed in the limestone 2504 far enough below the oil
sand/limestone
interface to provide adequate ground support for the tunnels. The tunnels 2505
would be
typically bored into the limestone by a hard rock tunnel boring machine since
the limestone is
typically self supporting. It is appreciated that some sections of the tunnels
2505 may require
ground support where the limestone is not competent. Access to the limestone
is typically by
vertical shafts sunk from the surface 2501 through the overburden 2502 and oil
sands 2503 and
terminating in the limestone 2504. The shafts are of a sufficient diameter to
accommodate
ventilation, access, and the large components of the tunneling machines.
Figure 24 is a schematic end view of two tunnels 2605 in a limestone formation
2604
showing well pairs 2606 drilled from the tunnels 2605 and well pairs 2607
drilled from a surface
location 2608 on a surface 2601 to intercept tunnels 2605. This is an
alternate method to that
shown in Figure 23 and can result in the same general layout of well pairs. An
advantage of the
configuration shown in Figure 24 is that well pairs 2607 and 2606 are both
accessible from either
end. The horizontal sections of well pairs 2607 are typically in the length
range of
approximately 100 to 1,000 meters but may be longer as surface drilling
techniques are
improved. Otherwise, tunnel diameters and spacing and well pair diameters and
spacing are the
same as those described in Figure 19. The methods of installing the well pairs
2606 between
adjacent tunnels 2605 are the same as those described in Figure 23.
Figure 25 is a schematic end view of two tunnels 2705 in a limestone formation
2704
showing single wells 2706 and well pairs 2707 drilled from the tunnels 2705.
The difference
between the configuration of Figure 25 and Figure 23 is that the horizontal
portions of the wells
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CA 02509268 2005-06-08
2706 drilled through the oil sand 2703 between tunnels 2705 are single wells
that can serve as
both steam injectors and mobilized bitumen collectors. Single well injection
and recovery is a
less developed technology than that based on using a well pairs where the
lower well is typically
the collector and the upper well is typically the injector. The major
advantage of using a single
well is that less drilling is required to drain a given reservoir volume.
Otherwise, tunnel
diameters and spacing and well pair diameters and spacing are the same as
those described in
Figure 19.
Figure 26 is a schematic end view of two tunnels 2805 in a limestone formation
2804
showing single wells 2806 drilled between adjacent tunnels 2805 and single
wells 2807 drilled
from a surface location 2810 on a surface 2801 to intercept tunnels 2805. This
is an alternate
method to that shown in Figure 25 and can result in the same general layout of
wells. An
advantage of the configuration shown in Figure 26 is that wells 2807 and 2806
are both
accessible from either end. The horizontal sections of wells 2808 are
typically in the length
range of approximately 100 to 1,000 meters but may be longer as surface
drilling techniques are
improved. Otherwise, tunnel diameters and spacing and well diameters and
spacing are the same
as those described in Figure 19.
A number of variations and modifications of the invention can be envisioned.
As will be
appreciated, it would be possible to provide for some features of the
invention without providing
others. For example, the various inventive features can be combined in various
ways with the
common feature that they are installed and operated from tunnels emplaced near
the bottom of
the oil sand deposits.
The present invention, in various embodiments, includes components, methods,
processes, systems and/or apparatus substantially as depicted and described
herein, including
various embodiments, sub-combinations, and subsets thereof. Those of skill in
the art will
understand how to make and use the present invention after understanding the
present disclosure.
The present invention, in various embodiments, includes providing devices and
processes in the
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CA 02509268 2005-06-08
absence of items not depicted and/or described herein or in various
embodiments hereof,
including in the absence of such items as may have been used in previous
devices or processes,
for example for improving performance, achieving ease and\or reducing cost of
implementation.
The foregoing discussion of the invention has been presented for purposes of
illustration
and description. The foregoing is not intended to limit the invention to the
form or forms
disclosed herein. In the foregoing Detailed Description for example, various
features of the
invention are grouped together in one or more embodiments for the purpose of
streamlining the
disclosure. This method of disclosure is not to be interpreted as reflecting
an intention that the
claimed invention requires more features than are expressly recited in each
claim. Rather, as the
following claims reflect, inventive aspects lie in less than all features of a
single foregoing
disclosed embodiment. Thus, the following claims are hereby incorporated into
this Detailed
Description, with each claim standing on its own as a separate preferred
embodiment of the
invention.
Moreover though the description of the invention has included description of
one or more
embodiments and certain variations and modifications, other variations and
modifications are
within the scope of the invention, e.g. as may be within the skill and
knowledge of those in the
art, after understanding the present disclosure. It is intended to obtain
rights which include
alternative embodiments to the extent permitted, including alternate,
interchangeable and/or
equivalent structures, functions, ranges or steps to those claimed, whether or
not such alternate,
interchangeable and/or equivalent structures, functions, ranges or steps are
disclosed herein, and
without intending to publicly dedicate any patentable subject matter.
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