Note: Descriptions are shown in the official language in which they were submitted.
CA 02641294 2008-10-17
LOW PRESSURE RECOVERY PROCESS FOR ACCELERATION OF IN-SITU BITUMEN
RECOVERY
FIELD OF THE INVENTION
[0001] The present invention relates generally to recovery processes of heavy
oil or
bitumeri from an underground oil-bearing reservoir by thermal methods. More
particularly,
the present invention relates to in-situ recovery of bitumen from an
underground oil-bearing
reservoir where the initial reservoir pressure is lower than what would be
expected via
hydrostatic pressure gradient due to regional geological effects, depleted gas
caps or other
thief zones, or lack of overlying cap rock. More particularly, the present
invention relates to
recovery processes where overlying underground strata are at low pressure due
to any one
or more of the factors above, the most common example of which is prior gas
production.
BACKGROUND OF THE INVENTION
[0002] A number of patents relate to the recovery of bitumen or heavy oil from
underground reservoirs by thermal methods.
[0003] Canadian Patent No. 1,130,201 (Butler) teaches a thermal method for
recovering highly viscous oil from bitumen deposit in unconsolidated sand by
means of
Steam Assisted Gravity Drainage (SAGD). The method consists of drilling two
long horizontal
wells, parallel and in the same direction, with one located several metres
above the other.
Steam is injected into the upper well, thermal communication is established
between the two
wells, and oil and water drain continuously to the lower well from where they
are pumped to
the surface.
[0004] Canadian Patent Nos. 2,015,459 and 2,015,460 (Kisman) teach a technique
of gas injection into a thief zone in a bitumen bearing sand. This thief zone
causes an
unwanted degree of lateral steam migration from the vertical wells; the gas
injection prevents
this unwanted lateral migration by establishing a confining pressure from
outside the well
pattern, so that the steam cannot escape.
[0005] Canadian Patent No. 2,277,378 (Cyr and Coates) teaches a thermal
process
for recovery of viscous hydrocarbon that is operated in a similar manner as
SAGD. A third
parallel and coextensive horizontal well is provided at a suitable lateral
distance from the
SAGD vvell pair described by Butler in Canadian Patent No. 1,130,201. The
purpose of the
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third is to practice cyclic steam stimulation in such a manner as to improve
the heat
distribution throughout the subterranean reservoir. In the SAGD well pair,
steam will tend to
rise to the top of the hydrocarbon bearing structure. By cyclic steam
stimulation at the third
well, steam injection is alternated with oil production to achieve a more
favourable heat
distribution than is possible with SAGD alone.
[0006] Canadian Patent Application No. 2,591,498 (Arthur, Gittins and Chhina)
teaches an extended SAGD process with a similar well configuration to patent
2,277,378 by
Cyr. The purpose is likewise to access a region of bitumen which would
normally be
bypassed by SAGD if operated in the manner taught by Butler. The purpose here
is to
access that portion of said reservoir whose hydrocarbons have not been or had
not been
recovered in the course of the ... gravity controlled process. The recovery
method from the
third well, referred to as an infill well, is expected to be a gravity
controlled process, though
not necessarily limited to SAGD. Reference is made to injection of light
hydrocarbons or
gases to maintain pressure once steam injection is discontinued.
[0007] Large deposit of oil sands exist in Alberta, Canada and other regions
where a
low pressure zone or loss zone such as a"thief' zone overlies the deposit, for
example
natural gas in contact or fluid communication with the bitumen or heavy oil,
where natural
gas has been produced or is present at low pressure for other reasons.
Similarly, there are
large deposits in which the bitumen resources are in direct contact with
overlying water
zones, resulting in some cases from the previous gas production. There are
also areas that
are at low initial reservoir pressure for reasons that are not apparent in the
immediate area,
but resuilt from regional geological features. Other reservoirs exist in
Canada and elsewhere
where ttiere is no identifiable cap rock in which to contain injected fluids.
In these conditions,
steam losses to the thief zone could be substantial, potentially impacting the
overall rate of
recovery.
[0008] It is therefore desirable to provide a method or process for
accelerating
bitumen production in these conditions.
[0009] The present invention is direct to the above conditions and accelerates
production from such reservoirs, or renders such bitumen or heavy oil volume
more readily
producible, without requiring remedial action, such as the re-injection of gas
into the low
pressure zone, which is being performed.
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SUMMARY OF THE INVENTION
[0010] A method for recovery of hydrocarbons from a subterranean reservoir by
operatirig two injector producer well pairs under conditions of steam assisted
gravity
drainage (SAGD) with a lateral drainage (LD) well between and substantially
parallel to the
two injector producer well pairs; the LD well is operated under conditions of
intermittent
steam injection and alternating oil, water and gas production; NCG is co-
injected with steam
into both the injector wells and the lateral drainage well at selected
intervals, and in selected
quantities in order to control the steam saturation of the SAGD steam chamber
and the rise
of the steam chamber, and to encourage lateral fluid communication between the
adjacent
well pairs and the LD well; controlling gas injection and production in order
to manipulate the
rise of the steam chamber to improve production of oil; operating the well
pairs and the LD
well under conditions of a steam chamber pressure that is initially and
briefly high to
establish a steam chamber, but thereafter may be reduced to as low as 200 kPa,
a process
of low pressure SAGD.
[0011] In the present invention, NCG is injected not to restrict horizontal
movement of
steam as in some of the background art, but to encourage horizontal movement
of the
steam. LD wells are not, primarily, placed to recover oil, but instead to
assist in controlling
the amount of gas in the SAGD steam chamber. Further control of the amount of
gas in the
SAGD steam chamber is affected by manipulation of the solubility of gas
components in
water, such that the components may be produced as needed to reduce the amount
of gas in
the steam chamber. The temperature and/or pressure is/are adjusted to provide
solubility
control. The process may utilize steam pressures as low as 200 kPa, whereas
the lowest
steam pressure thus far utilized in the field is 800 kPa, and the Alberta
Energy Resources
Conservation Board has previously recognized that a lower limit of 600 kPa is
feasible. The
invention therefore may be applicable to reservoirs with very low gas
pressures, where
recovery has not heretofore been attempted.
[0012] The process includes:
[0013] Controlling the steam saturation in the SAGD zone in such a manner that
the
vertical rise rate of the steam chamber is controlled to reduce and manage
steam loss or
breakthrough to low pressure zones, by means of controlled gas co-injection
with steam;
[0014] Introducing a lateral drainage (LD) well to control the amount of gas
present in
the steam chamber and to encourage horizontal rather than vertical migration
of the steam,
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thus taking advantage of the delayed vertical growth and/or breakthrough of
steam to the low
pressure zone or loss zone in order to obtain a sweep of the bitumen or heavy
oil;
[0015] Utilizing means to manipulate the solubility of steam zone gases in
water, thus
controlling the amount of gas in the steam chamber in concert with gas
production from the
LD well; and
[0016] Operating at low steam pressures.
[0017] Production of bitumen or heavy oil is thus possible in an accelerated
fashion,
and in reservoir conditions where the reservoir pressure is low.
[0018] It is an object of the present invention to obviate or mitigate at
least one
disadvantage of previous methods and processes for bitumen recovery.
[0019] In a first aspect, the present invention provides a method of producing
hydrocarbons from a subterranean reservoir at least partially overlain by a
low pressure zone
or loss zone including providing a SAGD well pair, including an injection well
and a
production well within the reservoir, providing a lateral drainage (LD) well,
laterally offset from
the SAGD well pair within the reservoir, initiating operation of the SAGD well
pair and the LD
well to create or promote a common steam chamber within the reservoir and
establish fluid
communication among the injection well, production well, and the LD well,
injecting steam
into the steam chamber and withdrawing produced fluids from the steam chamber
to grow
the steam chamber vertically until a selected condition is met, and
selectively injecting non-
condensable gas (NCG) into the steam chamber at a selected rate and reducing
the
pressure of the steam chamber to create or expand a gas zone within the
reservoir and
create or promote a NCG buffer zone between the steam chamber and the low
pressure
zone or loss zone.
[0020] In one embodiment selectively injecting NCG into the steam chamber at a
low
rate anci reducing the pressure of the steam chamber is substantially
simultaneous.
[0021] In one embodiment the selected rate of NCG relative to steam is between
about 0.2 mol% and about 0.8 mol%.
[0022] In one embodiment the method further includes adjusting the amount of
NCG
in the sl:eam chamber by selectively injecting NCG into the LD well to
increase the amount of
NCG or producing fluids from the LD well to reduce the amount of NCG.
[0023] In one embodiment, adjusting the amount of NCG in the steam chamber
includes manipulating the solubility of the NCG or a particular NCG component
in water and
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bitumeri or heavy oil such that the produced fluids contain in solution the
amount of NCG or
NCG component desired to be removed (the solubility control).
[0024] In one embodiment the temperature and/or pressure is manipulated to
provide
solubility control.
[0025] In one embodiment NCG is co-injected via the injection well in the
presence of
steam, and NCG is intermittently injected or produced via the LD well for
control of the rise of
the steam zone, in conjunction with solubility control.
[0026] In one embodiment the NCG buffer zone extends between a hot zone and a
cold zone within the reservoir.
[0027] In one embodiment the selected condition is a selected portion of the
thickness of the reservoir. In one embodiment the selected portion is between
about 50%
and about 75% of the thickness of the reservoir.
[0028] In one embodiment the selected condition is a selected steam saturation
level.
In one embodiment the selected steam saturation is between about 70% and about
80%.
[0029] In one embodiment the selected condition is a period of time. In one
embodiment, the time is between about six (6) months and about sixty (60)
months from first
steam.
[0030] In one embodiment, the pressure of the steam chamber is reduced in a
stepwise manner.
[0031] In one embodiment the pressure of the steam chamber is reduced in a
plurality of steps over a pressure reduction time. In one embodiment, the
pressure reduction
time is substantially six months or more.
[0032] In one embodiment, the low pressure zone or loss zone is selected from
the
group of a low pressure gas zone, a gas or water zone in fluid communication
with a low
pressure gas zone, and a thief zone.
[0033] In one embodiment the operation of the SAGD well pair is initiated by
the
injection of high steam pressure into the injection well and the production
well to promote
fluid communication between the injection well and the production well.
[0034] In one embodiment the operation of the LD well is initiated by cyclic
steam
stimulation.
[0035] In one embodiment the NCG is injected through the injection well. In
one
embodiment the NCG is injected through the LD well.
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[0036] In one embodiment the method further includes monitoring the height of
the
steam chamber in the reservoir.
[0037] In one embodiment the low pressure zone or loss zone is a low pressure
gas
zone, the pressure of the low pressure gas zone between about 200 kPa and
about 1000
kPa.
[0038] In one embodiment the NCG is natural gas, combustion flue gas, modified
combustion flue gas, carbon dioxide, air, gas mixtures consisting
predominantly of nitrogen,
tracer gas, or mixtures thereof.
[0039] In one embodiment the low pressure gas zone, or other zone in
communication with a low pressure zone, is at a pressure of between about 200
kPa and
about 1000 kPa.
[0040] In one embodiment the NCG is complemented or replaced by a light
solvent.
In one embodiment the light solvent comprising propane, butane, butane
isomers, pentane,
pentane isomers, hexane, hexane isomers, heptane, heptane isomers, benzene,
toluene.
[0041] In one embodiment, the method further includes injecting a combustion
sustaining fluid, and igniting a mixture of the combustion sustaining fluid
and the hydrocarbon
within the reservoir to provide a late stage sweep.
[0042] Other aspects and features of the present invention will become
apparent to
those ordinarily skilled in the art upon review of the following description
of specific
embodiments of the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0043] Embodiments of the present invention will now be described, by way of
example only, with reference to the attached Figures, wherein:
Fig. 1 is a schematic of an embodiment of the present invention;
Fig. 2 is a graph of an example of steam saturation control of an embodiment
of the present invention;
Fig. 3 is a graph of an example of produced gas via solubility control of an
E:mbodiment of the present invention; and
Fig. 4 is a graph of an example of LD well production of an embodiment of the
present invention.
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DETAII_ED DESCRIPTION
[0044] Generally, the present invention provides a low pressure recovery
process for
acceleration of in-situ bitumen recovery.
[0045] The objective of the invention is to accelerate production and increase
recovery of bitumen and/or heavy oil from reservoirs in contact with low
pressure
subterranean zones, due to factors such as regional geology, depleted gas caps
or other
thief zones, or lack of cap rock. The invention will hereinafter be referred
to as the SAGD
Triplet Process.
[0046] Referring to Fig. 1, a reservoir of bitumen or heavy oil 10 sits below
a low
pressure zone or loss zone 20, for example a low pressure (gas) zone 30. A
first SAGD well
pair 40 having an injection well 50 and a production well 60, and a second
SAGD well pair 70
having an injection well 80 and a production well 90 (together the first SAGD
well pair 40 and
the second SAGD well pair 70 forming adjacent SAGD well pairs 100) are drilled
at close
lateral spacing of 80m or greater, as suitable for reservoir conditions.
[0047] A horizontal lateral drainage (LD) well 110 is provided between the
adjacent
SAGD well pairs 100. The LD well 110 may intermittently alternate between
injection and
production cycles. While the LD well 110 will inevitably produce some oil and
water from the
reservoir 10, the main purpose of the LD well 110 is to control the amount of
gas 120 in a
steam chamber 130 (formed when steam 140 is injected into the reservoir 10) at
any given
time, in concert with manipulation of gas solubility in water. This action
promotes lateral
communication between the adjacent SAGD well pairs 100, while causing the
steam
chamber 130 to rise at a reduced rate towards the low pressure gas zone 30. As
the steam
chamber 130 grows within the reservoir 10, a hot zone 170 expands while a cold
zone 180
shrinks as the heat from the steam 140 is delivered to the reservoir 10.
[0048] Low volumes of non-condensable gas (NCG) 150 may be co-injected into
the
injection wells 50,80 and the LD well 110 at selected intervals to control or
optimize the
growth of the steam chamber 130. Preferably between about 0 mol% and about 0.8
mol%
NCG 150 is intermittently introduced into the steam chamber 130. A NCG buffer
zone 190
forms between the steam chamber 130 and the low pressure zone or loss zone 20.
The NCG
150 will inhibit or limit the vertical rise rate of the steam chamber 130,
allowing the LD well
110 to promote lateral communication and lessen the impact of the low pressure
zone 30
above the reservoir of bitumen or heavy oil 10. Steam 140 is substantially
continuously
injected via the injection wells 50,80, and intermittently augmented by NCG
150. Steam 140
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CA 02641294 2008-10-17
is interrnittently injected via the LD well 110 and augmented by NCG 150. The
LD well 110
may provide gas production and gas injection as required to control the amount
of gas 120 in
the steam chamber 130.
[0049] As used herein, gas 120 includes solution gas (for example methane,
nitrogen
etc.) reaction gas (for example H2S, C02 etc.) and NCG 150 injected (for
example natural
gas, combustion flue gas, modified combustion flue gas such as oxygen removed
by
scavenging or otherwise, carbon dioxide, oxygen, air, gas mixtures comprising
predominantly
of nitrogen, mixes thereof, and other gases known to one skilled in the art).
[0050] Use of the LD well 110 for either injection or production is dictated
by the
nature of the reservoir 10 and selected by one skilled in the art of SAGD.
While some of the
background art may peripherally refer to continuous injection of gas or light
hydrocarbons
into a thief zone above or adjacent the bitumen or heavy oil to maintain or
build pressure, the
present invention requires controlled intermittent injection of NCG 150 or
light hydrocarbons
into the steam chamber 130. Continuous injection would be detrimental in the
application of
this invention. As one skilled in the art will recognize, larger amounts of
NCG 150 injected
into the steam chamber 130 affect the equilibrium of the steam in the steam
chamber 130
and as little as 0.8 mol% NCG 150 in steam 140 have been predicted to at least
partially
collapse the steam chamber 130 under certain conditions.
[0051] The amount of NCG 150 and certain NCG components in the steam chamber
130 at any given time may be controlled.
[0052] It is known that gases that are normally insoluble in water/steam
become
soluble at high temperature and pressure. A method of controlling the presence
of NCG 150
or individual NCG components, based on solubility control is provided, whereby
solubility
manipullation permits gas 120 / NCG 150 removal via water production and/or
oil production.
[0053] Figs. 3 and 4 illustrate typical gas removal trends and rates by
solubility
control and LD well 110 control at various stages of the process. Fig. 4 also
illustrates typical
water and oil production trends and rates.
[0054] The operating pressure in the adjacent SAGD well pairs 100 and the LD
well
110 is reduced as the steam chamber 130 rises to balance with the low initial
reservoir
pressure. In the case where the low pressure zone or loss zone 20 is a
depleted gas cap, the
operatirig pressure may be reduced to substantially balance with the pressure
of the
depleted gas cap. The process can operate at low pressures, for exampie about
as low as
200 kPa, whereas the lowest steam pressure thus far utilized in the field is
800 kPa, and the
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Alberta Energy Resources Conservation Board has previously recognized that a
lower limit
of 600 kPa is feasible. The invention therefore may be applicable to
reservoirs with very low
gas pressures, where recovery has not heretofore been attempted.
[0055] Low Pressure SAGD
[0056] Pumps suitable for oil production at low pressure SAGD conditions are
used.
These pumps are landed at or close to horizontally in the production wells
60,90. This, in
combination with the low net positive suction head allows for pump inlet
pressures as low as
200 kPaa.
[0057] Non-Condensable Gas Iniection / Co-Iniection
[0058] Carefully managed intermittent NCG 150 co-injection is used to control
steam
chamber 130 rise rates, thereby reducing the impact of the low pressure zone
30 above the
bitumeni, such as those that have been pressure depleted by prior gas
production. This
encourages lateral growth of the steam chamber 130, improving sweep efficiency
of the
process.
[0059] NCG behaviour in SAGD is governed by the following principles:
[0060] First. NCG 150 (methane, flue gas, modified flue gas, and other gases)
have
relatively low densities and will migrate toward the top of the steam chamber
130, providing a
buffer zone 160 between the steam chamber 130 and the overlying low pressure
zone or
loss zorie 20, such as the low pressure zone 30. Heat loss and steam loss to
the low
pressure zone or loss zone 20 are also controlled or reduced.
[0061] Second. Injection of NCG 150 in SAGD will cause a portion of the steam
140
in the steam chamber 130 to condense, thereby releasing latent heat to the
reservoir 10 and
therefore reduces the quality of the steam 140 in the steam chamber 130. Small
volumes of
NCG 150 injected with steam 140 will result in a bitumen production increase
due to the
additional latent heat transfer. Over-injection of NCG 130 could cause
instability, damage or
collapse of the steam chamber 130, negatively impacting overall production and
oil recovery.
Thus, the injection of NCG 150 (whether alone or co-injected with steam) as
well as the
amount of NCG 150 present in the steam chamber 130 should be carefully and
substantially
continuously controlled during operations.
[0062] Third. At certain SAGD conditions, the injected NCG 150 has similar or
greater ;solubility in water than in heavy oil or bitumen; therefore at least
a portion of the co-
injected NCG 150 or other gas is removed from the steam chamber 130 by
solution in
bitumen and produced water (for example, see Figs. 3 and 4). A sample
calculation for the
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control of steam saturation in the steam chamber 130 is illustrated in Fig. 2.
In the initial or
early stages of operation, the steam chamber 130 is created or expanded at
high pressures
(temperatures), for example about 3500 kPa steam at about 240 C for about 25m
of pay (as
would be known to one skilled in the art as a suitable pressure for the
Athabasca Oil Sands
in Alberta, Canada) or some pressure dictated by the reservoir properties.
[0063] In the early stages, there is little to substantially no accumulation
of NCG 150
in the steam chamber 130 because substantially all of the gases that normally
arise in SAGD
(for example including reaction gas and solution gas and other gases) are
produced due to
their sollubility in the oil or water.
[0064] At some selected condition, for example the peak of steam saturation
(see
Fig. 2), NCG 150 is co-injected with the steam 140 and the pressure is
reduced. The
pressure may be reduced gradually, for example through a number of steps down
over a
period of time. Gas 120 is produced more slowly, and intermittent NCG 150
injection or NCG
productiion via the LD well 110 is used to control the NCG 150 in concert with
solubility
control of NCG 150 production.
[0065] In the later stages of operation, most production of the gas 120 takes
place via
the LD iivell 110. The steam saturation, as shown in Fig. 2, is kept
substantially at a level that
provides control of the time of steam breakthrough to the low pressure zone or
loss zone 20
to improve cumulative recovery of the bitumen or heavy oil resource from the
reservoir 10.
[0066] These principles allow for the development of NCG injection strategies
to
manage and optimize steam chamber growth.
[0067] Well Configuration and Operating Strategy
[0068] The adjacent SAGD well pairs 100 are started up at an operating
pressure of
approxirnately 3500 kPa (as above, for the reasons above), or a pressure
defined by the
reservoir characteristics. This, first steam, pressure is chosen to be within
a safe operating
range, and will provide higher initial production rates and faster warm up.
This higher
temperature start up contributes to the commercial success of the process by
accelerating
productlon and improving lateral sweep and bitumen recovery.
[0069] Once the steam chamber 130 has formed to a selected condition (for
example
to a selected height in the reservoir, or after a selected period of time, or
some other
condition known to one skilled in the art), steam pressures are progressively
lowered to
control expansion of the steam chamber 130, and NCG 150 is injected at low
rates and in a
controlled manner to control and optimize the rise rate of the steam chamber
130 and
10.
CA 02641294 2008-10-17
prevent negative impacts of breakthrough or steam loss to the low pressure
zone or loss
zone 20, and to encourage lateral growth of the steam chamber 130 by means of
manipulation production of gas 120 at the LD well 110.
[0070] High Temperature Oxidation / Combustion
[0071] In an alternative embodiment, air or other combustion sustaining fluid
may be
injectecl rather than the NCG 150, such that, with ignition, combustion occurs
within the
reservoir 10 and provide a late stage sweep. This would typically be a wind
down strategy
after the horizontal sweep.
[0072] Further Benefits of the Invention
[0073] The invention may be utilized to reduce greenhouse gas emissions in at
least
two ways:
[0074] First, the low pressure operation requires less energy to convert a
cubic metre
of water to steam than does operation of SAGD at higher steam pressure; in the
SAGD
Triplet Process, it is possible to operate at temperatures of 150 C (300 F)
or less, whereas
typical SAGD operations to date have utilized temperatures between 165 C (330
F) and
270 C (520 F). Accordingly, less fuel, which is typically natural gas for
combustion, is
requireci to convert boiler feed water to steam, and the resulting efficiency
reduces the
amount of carbon dioxide that is emitted to the atmosphere in the generation
of steam for
SAGD.
[0075] As one skilled in the art recognizes, typical SAGD operations (and the
present
invention) utilize substantially saturated steam, and thus generally a
reference to a steam
pressure is also a reference to the corresponding saturated steam temperature
and vice
versa. However, wet steam and/or superheated steam may alternatively be used.
[0076] Second, the NCG 150 utilized for co-injection with steam 140 may be
chosen
to be fluie gas from the steam generation process. The flue gas may contain
approximately
11 % by volume of carbon dioxide. Sound theoretical calculations predict that
only a relatively
small fraction of this carbon dioxide will be produced back with oil and water
in the SAGD
Triplet F'rocess, and thus geological sequestration of the injected carbon
dioxide is achieved.
While the amount of this geological sequestration is relatively small compared
to that of
deeper, high pressure reservoirs, it does measurably reduce the carbon dioxide
footprint of
the recovery of bitumen by other SAGD processes. The details will be dependent
on the
steam pressure chosen in a particular application of the invention, but may be
readily
determined by one skilled in the art.
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[0077] Applications
[0078] The present invention applies to any heavy oil or bitumen deposit where
the
initial reservoir pressure is low, due to regional geological factors, or in
which the overlying
zone is at low pressure due to gas production or to any other cause. The
pattern of the well
arrangement shown may be repeated in parallel to the wells shown, and the
following are the
aspects of the invention:
[0079] The adjacent SAGD well pairs 100 are drilled and completed with
substantially
parallel trajectories, where the injection well 50,80 lies a few meters above
the corresponding
production well 60,90;
[0080] Substantially parallel to the adjacent SAGD well pairs 100, at a
distance to be
selected by one skilled in the art considering reservoir characteristics, but
usually 30 metres
or greater, the LD well 110 of generally the same length is drilled and
completed.
[0081] This arrangement may be repeated at will. While Fig. 1 shows an
embodiment
having adjacent SAGD well pairs 100 with an intermediate LD well 100, one
skilled in the art
recognizes that the invention may be practiced in other configurations
including a single
SAGD well pair with a LD well (such as the first SAGD well pair 40 and the LD
well 110) or
multiple LD wells may be provided within the steam chamber 130.
[0082] The production wells 60,90 and the LD well 110 are equipped with pumps
suitable for oil or water production at low pressure and temperature of steam,
for example
progressing cavity pumps, such as metal-metal progressing cavity pumps. The
equipment is
suitable for production of oil and water at steam temperatures and pressures
well below
those o1" normal SAGD operations in Alberta.
[0083] The injection wells 50,80 and LD well 110 are fitted with equipment
that
permits the intermittent injection and production of NCG 150, including but
not limited to
natural gas, flue gases from steam generation, nitrogen or gases where the
nitrogen content
predominates, or tracer gases that may be used to study the fluid behaviour of
the reservoir.
[0084] The injection rates of NCG are intermittent rather than continuous, are
selectably varied from time to time as desired from the data pertaining to the
project
operations.
[0085] In the preceding description, for purposes of explanation, numerous
details
are set forth in order to provide a thorough understanding of the embodiments
of the
invention. However, it will be apparent to one skilled in the art that these
specific details are
not required in order to practice the invention.
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CA 02641294 2008-10-17
[0086] The above-described embodiments of the invention are intended to be
examples only. Alterations, modifications and variations can be effected to
the particular
embodiments by those of skill in the art without departing from the scope of
the invention,
which is defined solely by the claims appended hereto.
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