Note: Descriptions are shown in the official language in which they were submitted.
WELL CONFIGURATIONS FOR LIMITED REFLUX
FIELD OF THE INVENTION
[0002] Embodiments of the invention relate to producing hydrocarbons by
steam
assisted gravity drainage with dual producers separated vertically and
laterally from at
least one injector.
BACKGROUND OF THE INVENTION
[0003] Bitumen recovery from oil sands presents technical and economic
challenges
due to high viscosity of the bitumen at reservoir conditions. Steam assisted
gravity
drainage (SAGD) provides one process for producing the bitumen from a
reservoir.
During SAGD operations, steam introduced into the reservoir through a
horizontal
injector well transfers heat upon condensation and develops a steam chamber in
the
reservoir. The bitumen with reduced viscosity due to this heating drains
together with
steam condensate along a boundary of the steam chamber and is recovered via a
producer
well placed parallel and beneath the injector well.
[0004] However, costs associated with energy requirements for the SAGD
operations
limit economic returns. Accumulation in the reservoir of gaseous carbon
dioxide (CO2)
and/or solvent that may be injected with the steam in some applications can
further
present problems. For example, the gaseous CO2/solvent acts as a thermal
insulator
impairing heat transfer from the steam to the bitumen, decreases temperature
of the
drainage interface due to partial pressure impact, and decreases effective
permeability to
oil as a result of increased gas saturation.
[0005] Therefore, a need exists for methods and systems for recovering
hydrocarbons
from oil sands with an efficient steam-to-oil ratio.
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BRIEF SUMMARY OF THE DISCLOSURE
[0006] In one embodiment, a method of recovering hydrocarbons includes
introducing a gaseous mixture including steam and non-condensible gas (NCG)
into an
injection well. The mixture passes into a formation through a horizontal
length of the
injection well. The method further includes recovering a petroleum fluid from
first and
second production wells spaced laterally from one another by at least 10
meters and
oriented horizontal and parallel to the horizontal length of the injection
well that is
disposed in vertical alignment 1 to 10 meters above a midpoint between the
production
wells.
[0007] According to one embodiment, a method of recovering hydrocarbons
includes
introducing a gaseous mixture including steam and NCG into an injection well
having a
horizontal length through which the mixture passes into a formation. In
addition, a steam
chamber generates within the formation along with drainage pathways at a
boundary of
the chamber that end at first and second production wells and remain below a
threshold
temperature for retaining the NCG in solution due to location of the
production wells
below and on each side of the injection well. The method also includes
recovering a
petroleum fluid from the production wells that are oriented horizontal and
parallel to the
horizontal length of the injection well.
[0008] For one embodiment, a system for recovering hydrocarbons includes an
injection well disposed in a formation and in fluid communication with a
gaseous mixture
of steam and NCG. The injection well includes a horizontal length thereof
through which
the mixture is passable into the formation. The system further includes first
and second
production wells spaced laterally from one another by at least 10 meters and
oriented
horizontal and parallel to the horizontal length of the injection well that is
disposed in
vertical alignment 1 to 10 meters above a midpoint between the production
wells through
which a petroleum fluid is recoverable.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] A more complete understanding of the present invention and benefits
thereof
may be acquired by referring to the follow description taken in conjunction
with the
accompanying drawings.
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[0010] Figure 1 is a schematic of an injector with dual producers in a
steam assisted
gravity drainage operation, according to one embodiment of the invention.
[0011] Figure 2 is a schematic of dual injectors with dual producers in a
steam
assisted gravity drainage operation, according to one embodiment of the
invention.
[0012] Figure 3 is a graph of oil production rate versus time for
comparison of
simulated results based on well configurations such as shown in Figure 1,
according to
one embodiment of the invention.
[0013] Figure 4 is a graph of cumulative steam to oil ratio versus time for
comparison
of simulated results based on well configurations such as shown in Figure 1,
according to
one embodiment of the invention.
[0014] Figure 5 is a graph of oil production rate versus time for
comparison of
simulated results based on well configurations such as shown in Figure 2,
according to
one embodiment of the invention.
[0015] Figure 6 is a graph of cumulative steam to oil ratio versus time for
comparison
of simulated results based on well configurations such as shown in Figure 2,
according to
one embodiment of the invention.
DETAILED DESCRIPTION
[0016] Turning now to the detailed description of the preferred arrangement
or
arrangements of the present invention, it should be understood that the
inventive features
and concepts may be manifested in other arrangements and that the scope of the
invention
is not limited to the embodiments described or illustrated. The scope of the
invention is
intended only to be limited by the scope of the claims that follow.
[0017] For some embodiments, methods and systems produce petroleum products
by
steam assisted gravity drainage (SAGD) with dual producers separated
vertically and
laterally from at least one injector. Placement of the producers limits
temperature rise of
draining fluids and hence reflux of non-condensable gases (NCG) injected with
steam. In
particular, the fluids drain along a steam chamber boundary for recovery at
positions that
are not in a direct downward path from where the injector is introducing heat
into the
formation.
[0018] The NCG refers to a chemical that remains in the gaseous phase under
process
conditions within the formation. Examples of the NCG include, but are not
limited to,
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air, carbon dioxide (CO2), nitrogen (N2), carbon monoxide (CO), hydrogen
sulfide (H2S),
hydrogen (H2), anhydrous ammonia (NH3) and flue gas. Flue gas or combustion
gas
refers to an exhaust gas from a combustion process that may otherwise exit to
the
atmosphere via a pipe or channel. Flue gas often comprises nitrogen, CO2,
water vapor,
oxygen, CO, nitrogen oxides (NO) and sulfur oxides (SO). The NCG can make up
from 1 to 40 volume percent of a mixture that is injected into the formation.
[0019] As used
herein, hydrocarbon solvent refers to a chemical consisting of carbon
and hydrogen atoms which dissolves into products being recovered to increase
fluidity
and/or decrease viscosity of the products. The hydrocarbon solvent can have,
for
example, 1 to 12 carbon atoms (C1¨C12) or 1 to 4 carbon atoms (C1¨C4) per
molecule.
The C1 to C4 hydrocarbon solvent may include methane, ethane, propane and/or
butane.
The hydrocarbon solvent can be introduced into the formation as a gas or as a
liquid.
Under the pressures of the formation, the hydrocarbon solvent may be another
example of
the NCG or may condense from a gas to a liquid, especially if the hydrocarbon
solvent
has 2 or more carbon atoms.
[0020] Given high
energy costs of SAGD, steam co-injection with carbon dioxide
and/or hydrocarbon solvents provides one option in some embodiments for
reducing the
energy used by reducing heat losses and facilitating viscosity reduction. The
NCG, for
example, may accumulate in an upper part of the steam chamber where the NCG
acts as
insulation for reducing heat loss to overburden. However, too much
accumulation of the
NCG may suppress production.
[0021] For
example, the NCG at a side boundary of the steam chamber may act as a
thermal insulating blanket that impairs transport of heat from the steam to
the bitumen.
Due to the partial pressure effect, the temperature of the drainage interface
decreases and
the bitumen that drains along the boundary also becomes less mobile. Gas
saturation
increases as a direct result of NCG accumulation at the drainage interface
such that the
effective permeability to oil decreases.
[0022] Some of the
NCG that accumulates in the steam chamber comes from
refluxing of the NCG dissolved in the draining fluids prior to recovery. The
NCG
liberates from the fluid in liquid phase back into gaseous phase that then
moves upward
into the steam chamber. Solubility of the NCG in the draining fluids depends
on
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temperature. For example, minimal carbon dioxide dissolves in bitumen at steam
chamber temperatures above 200 C but will dissolve in the bitumen at lower
temperatures along a boundary of the steam chamber.
[0023]
Increase in temperature of the draining fluid due to heat transfer near the
injector depends on proximity of the draining fluid passing by the injector.
As described
herein for some embodiments, drainage pathways at a boundary of the steam
chamber
that end at the production wells remain below a threshold temperature for
retaining the
NCG in solution. Prior well configurations and operations by contrast provided
undesired temperature profiles in the formation causing effervescence of the
NCG from
the bitumen, resulting in the reflux of the NCG into the steam chamber.
[0024]
Since direct steam generator products have the NCG (e.g., 10 to 12 weight
percent carbon dioxide) intermixed with steam, direct steam generation when
used to
supply a SAGD process according to some embodiments may reduce the steam-oil
ratio
and improve economic recovery. The direct steam generation also consumes less
water
compared to conventional steam generation. However, the NCG from the direct
steam
generator products may accumulate in the steam chamber to a level more than
desired
without utilizing approaches described herein.
[0025] The
direct steam generation refers to making steam by direct contact of water
with combustion and hot combustion products. Typically, direct steam
generators
include a combustion zone, a plurality of mixing zones downstream from the
combustion
zone, and an exhaust barrel downstream from the mixing zones. As an example, a
direct
steam generator such as that described in U.S. Pat. No. 6,206,684 (assigned to
Clean
Energy Systems) can be used or modified for some embodiments.
[0026]
Figure 1 shows an injection well 100 disposed above a first production well
102 and a second production well 103 within a formation. While viewed
transverse to a
horizontal length, the wells 100, 102, 103 include horizontal sections that
traverse
through the formation containing petroleum products, such as heavy oil or
bitumen. In
operation, a steam chamber 104 develops as a mixture of steam and NCG is
introduced
into the formation through the injection well 100 and a resulting petroleum
fluid is
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recovered from the production wells 102, 103. Use of the productions wells
102, 103 for
this recovery may begin upon initial development of the steam chamber 104.
[0027] The steam
and the NCG contacts the bitumen, condenses and/or dissolves in
the bitumen if soluble. Heat transfer upon condensation and solvent based
viscosity
reduction makes the bitumen mobile and enables gravity drainage thereof. The
petroleum fluid of steam condensate, the bitumen and any dissolved NCG
migrates
through the formation due to gravity and is gathered at each of the production
wells 102,
103 for recovery to surface.
[0028] In some
embodiments, a distance of at least 10 meters separates the first
production well 102 from the second production well 103, which are spaced
laterally
from one another and oriented horizontal and parallel to a horizontal length
of the
injection well 100. Lateral spacing of the production wells 102, 103 promotes
lateral
development of the steam chamber 104. In some embodiments, the steam chamber
104
generation occurs without recovery of the petroleum fluid in an area of the
formation
having vertical alignment with the injection well 100. The injection well 100
for some
embodiments aligns in a vertical direction 1 to 10 meters above a midpoint
between the
production wells 102, 103.
[0029] In some
embodiments, spacing between the first and second production wells
102, 103 ranges from 10 to 20 meters. With such spacing, the first and second
production wells 102, 103 rely only on fluid communication being established
during
startup with the injection well 100. Any additional adjacent injection wells
associated
with corresponding production wells may be too far off for effective fluid
communication
at startup without creating such a tight spacing of all wells to be
uneconomical.
Multilaterals may form the first and second production wells 102, 103, which
thus
connect to a vertical common wellbore instead of separate independent
wellbores for
each of the production wells 102, 103. The productions wells 102, 103 may
extend along
a bottom of a hydrocarbon reservoir in the formation and may be disposed in a
common
horizontal plane.
[0030] This
operation and configuration of the wells 100, 102, 103 provides a desired
temperature profile in the formation and limits reflux and accumulation of the
NCG, such
as the carbon dioxide. Drainage pathways at a boundary of the steam chamber
104
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terminate at the production wells 102, 103 and remain below a threshold
temperature for
retaining the NCG in solution. Limiting the accumulation of the NCG promotes
growth
of the steam chamber 104, which also develops with a desired shape by
employing
approaches described herein.
[0031] Figure 2
illustrates an injection well 200 disposed below an auxiliary well 201
and above a first production well 202 and a second production well 203 within
a
formation. The auxiliary well 201 supplements the injection well 200 in
introducing a
mixture of steam and NCG into the formation and may further facilitate
creation of a
desired temperature profile within the formation. The injection well 200 and
production
wells 202, 203 otherwise correspond in function and design as like elements
described
herein with respect to Figure 1.
[0032] In some
embodiments, the auxiliary well 201 aligns in a vertical direction at
least 5 meters, or between 10 and 20 meters, above a horizontal length of the
injection
well 200. The auxiliary well extends parallel with the horizontal length of
the injection
well 200. For example, the injection well 200 may pass through the formation 5
meters
above a horizontal plane of the production wells 202, 203 with the auxiliary
well 201
disposed 5 meters above the injection well 200.
[0033] In
operation, the mixture of the steam and NCG may pass through both the
injection well 200 and the auxiliary well 201 simultaneously. An alternative
staged
strategy shuts in the injection well 200 stopping introduction of the mixture
via the
injection well 200 before injecting the mixture into the auxiliary well 201.
Shutting in
the injection well 200 may occur once thermal communication is established
between the
auxiliary well 201 and the production wells 202, 203 (e.g., after about 2
years).
[0034] Figure 3
shows simulated results for oil production rate versus time with a
first curve 301 corresponding to a conventional steam only vertical aligned
SAGD well
pair, a second curve 302 corresponding to a well configuration as depicted in
Figure 1
and operating with a direct steam generator, and a third curve 303
corresponding to the
SAGD well pair operating with the direct steam generator. The oil production
rate thus
improves with the well configuration as depicted in Figure 1. In particular,
the second
curve 302 remains about the third curve 303 throughout most of the time and is
above the
first curve 301 as the time progresses.
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. =
[0035] Figure 4 illustrates simulated results for cumulative steam to
oil ratio versus
time with a first curve 401 corresponding to a conventional steam only
vertical aligned
SAGD well pair, a second curve 402 corresponding to a well configuration as
depicted in
Figure 1 and operating with a direct steam generator, and a third curve 403
corresponding
to the SAGD well pair operating with the direct steam generator. The second
curve 402
remains below the first and third curves 401, 403 most of the time.
Accordingly,
embodiments described herein retain superior energy efficiency obtained by use
of the
direct steam generator as evidenced by a more than 20% reduction in the
cumulative
steam to oil ratio compared to steam only SAGD.
[0036] Figure 5 shows simulated results for oil production rate versus
time with a
first curve 501 corresponding to a conventional steam only vertical aligned
SAGD well
pair, a second curve 502 corresponding to a well configuration as depicted in
Figure 2
and operating with a direct steam generator, and a third curve 503
corresponding to the
SAGD well pair operating with the direct steam generator. The oil production
rate thus
improves with the well configuration as depicted in Figure 2. Like Figure 3,
the second
curve 502 remains about the third curve 503 throughout most of the time and is
above the
first curve 501 as the time progresses.
[0037] Figure 6 illustrates simulated results for cumulative steam to
oil ratio versus
time with a first curve 601 corresponding to a conventional steam only
vertical aligned
SAGD well pair, a second curve 602 corresponding to a well configuration as
depicted in
Figure 2 and operating with a direct steam generator, and a third curve 603
corresponding
to the SAGD well pair operating with the direct steam generator. Similar to
Figure 4, the
second curve 602 remains below the first and third curves 601, 603 most of the
time.
Accordingly, embodiments described herein retain superior energy efficiency
obtained by
use of the direct steam generator as evidenced by a more than 20% reduction in
the
cumulative steam to oil ratio compared to steam only SAGD.
[0038] In closing, it should be noted that the discussion of any
reference is not an
admission that it is prior art to the present invention, especially any
reference that may
have a publication date after the priority date of this application.
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[0039] Although
the systems and processes described herein have been described in
detail, it should be understood that various changes, substitutions, and
alterations can be
made without departing from the spirit and scope of the invention as defined
by the
following claims. Those skilled in the art may be able to study the preferred
embodiments and identify other ways to practice the invention that are not
exactly as
described herein. It is the intent of the inventors that variations and
equivalents of the
invention are within the scope of the claims, while the description, abstract
and drawings
are not to be used to limit the scope of the invention. The invention is
specifically
intended to be as broad as the claims below and their equivalents.
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