Note: Descriptions are shown in the official language in which they were submitted.
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OIL RECOVERY PROCESS
FIELD OF THE INVENTION
[00031 Method
of recovering heavy oil with an injection well and a production well,
wherein the depth of the production well is below the injection well.
BACKGROUND OF THE INVENTION
[00041 Steam
Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS),
also referred to as the 'Huff and Puff' process, are the two most commonly
used methods for
recovering bitumen and heavy viscous oils from subterranean formations. In a
SAGD
method a pair horizontal wells serve both as an injector well and a production
well. The
injector well and the production well extend downwardly from the surface of
the earth into
the oil bearing stratum and then extend horizontally through the stratum. The
horizontal
portion of the production well is placed at the base of the oil bearing
stratum and the
horizontal leg of the injector well is placed at an optimal distance above and
parallel to the
production well. Steam is injected continuously into the stratum through the
top well. Upon
entering the stratum, the steam releases it latent heat to the stratum,
thereby heating and
lowering the viscosity in the formation and improving the mobility of the oil.
The heated oil
with condensed steam flows down under gravity toward the bottom production
well from
which it is produced.
[0005] Cyclic
steam stimulation or the 'huff and puff process is another commonly used
method for recovering heavy viscous oils or bitumen from the subterranean
formation. This
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process involves injecting a predetermined volume of steam into a stratum
through a single
vertical well for a selected duration, stopping the injection of steam,
permitting the stratum to
soak and followed by producing oil through the same well. Unfortunately, CSS
has a
number of limitations because it is a single well process and the recovery
zone is limited to
the near well bore region. Most notably, the ability to improve recovery
requires CSS to drill
a large number of wells.
[0006] There are a variety of problems associated with the `SAGD' and the
'Huff and
Puff processes. A commonly used criterion to establish the efficiency of a
steam based oil
recovery process is the steam oil ratio (SOR). SOR is the measure of barrels
of steam needed
to produce one barrel of oil. Both thermal and recovery efficiency (and by
implication the
economics) of the process is a function of SOR. A smaller SOR implies higher
thermal
efficiency and better economics. Both SAGD and CSS are thermally inefficient.
A major
drawback of the SAGD processes is that it requires large volumes of high
quality (90-100%
quality) steam to heat the reservoir and recover oil at economic rate. In
thick, high quality
reservoir the SAGD recovery can exceed 50% of oil from the steam contacted
region at a
SOR greater than 3.0, but in thinner reservoir with lower oil saturations,
SORs are much
higher.
[0007] Also SAGD oil recovery depends only on the available latent heat
content of the
steam (sensible heat has no value to the recovery process). Since the latent
heat content of
the steam decreases with increase in steam pressure the SGAD process becomes
uneconomic
if implemented at greater depth (reservoir pressure and consequently the steam
injection
pressure increases with depth). The use of surface generated steam as the heat
source also
limits the depth at which the process can be implemented due to conductive
heat losses
(degradation of steam quality) through the well bore.
[0008] Irrespective of reservoir quality, steam quality and oil saturation,
CSS recovery
method seldom exceeds 20% oil in place at SORs in excess of 5. Use of lower
quality steam
in the CSS process in reservoirs containing highly viscous oil is less
effective in lowering the
viscosity of the oil, limit the radius of invasion of the steam, lower the
reservoir sweep and
result in lower recovery due to slower rate of flow of higher viscosity oil
during the
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production cycle. In CSS processes high heat efficiency would be promoted by
lower
pressure and high quality steam. Thus processes that promote high recovery of
viscous oil at
lower SOR are needed. Conventional steam injection processes such as SAGD and
CSS
produce SOR in the excess of 3Ø
[00011 There exists a need to provide an improved viscous oil recovery
process that
overcome the limitations of SAGD and the CSS process to provide profitable
recovery of
heavy oil/bitumen from thinner formations than currently permitted with
conventional steam
heating processes.
SUMMARY OF THE INVENTION
[00021 A method for recovering heavy oil in a stratum with an injection
well, a
production well and a steam generator. The method begins by injecting steam
from the
steam generator into a horizontal portion of the injection well followed by
soaking the
stratum with the steam from the injection well for a predetermined period of
time followed
by producing heavy oil from the stratum with the production well. In the
method the depth
of a horizontal portion of the production well is below the horizontal portion
of the injection
well and the position of the steam generator is placed along the horizontal
portion of the
injection well.
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In accordance with one aspect of the present invention, there is provided a
method
comprising: a) injecting steam from a steam generator into a horizontal
portion of an injection
well; b) soaking a stratum with the steam from the injection well for a
predetermined period
of time; and c) producing heavy oil from the stratum with a production well
between multiple
cycles of the injecting steam and soaking the stratum, wherein the depth of a
horizontal
portion of the production well is below the horizontal portion of the
injection well such that
the injecting and the soaking results in draining the heavy oil produced with
the production
well and the position of the steam generator is placed along the horizontal
portion of the
injection well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] The invention, together with further advantages thereof, may best be
understood
by reference to the following description taken in conjunction with the
accompanying
drawings.
[0004] Figure 1 depicts a steam generator placed downhole in the injection
well.
[0005] Figure 2 depicts a steam generator placed along the horizontal
portion of the
injection well.
[0006] Figure 3 depicts a typical SAGD oil recovery process.
[0007] Figure 4 depicts a typical CSS oil recovery process.
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[0008] Figure 5 depicts one embodiment of the present oil recovery process.
DETAILED DESCRIPTION OF THE INVENTION
[0009] The present method of recovering heavy oil with an injection well
and a
production well through the use of steam generation. Recovery of the heavy oil
or bitumen is
accomplished by using steam generators placed downhole along the horizontal
portion of the
injection well. The orientation of the wells is placed so that the injection
well is located
above the production well, wherein the production well is utilized to produce
heated oil. The
pair of wells is oriented to take advantage of gravity segregation of the
steam and the oil to
decrease the production of hot water or steam and thereby increase the thermal
efficiency as
expressed as a steam to oil ratio.
[0010] Steam is generated in the steam generator located at the horizontal
portion of the
injector well, wherein the horizontal portion of the injector well extend from
the bottom
portion of the vertical portion of the injector well to the far end of the
horizontal section of
the injector well. Placement of the steam generator along the horizontal
portion results in
higher quality steam, nearing 100% quality steam, to be present downhole.
[0011] Criteria for the volume of steam to be injected per cycle, injected
steam quality,
injection duration, soak time and production duration have been established in
the art.
Generally the production cycle is of much longer duration compared to the
injection cycle or
soaks time. In bitumen reservoirs or in reservoirs where the oil is
practically immobile, the
injection and the production well vicinity is heated by circulating steam
through the casing ¨
tubing annulus or by other means to decrease the near well bore resistance, to
facilitate
injection of adequate volume of steam to lower bitumen viscosity and to
establish
communication between injector and the producer.
(0012] Steam and combustion gases are injected into the injection well in a
predetermined sequence from a steam generator housed in the injection well.
The injected
steam-combustion gas is allowed to soak for a brief period, from about 1-10
days, about 2-8
days or 3-6 days, to transfer the heat, reduce the viscosity of the oil and to
facilitate the
dissolution of a small fraction of the combustion gas into the heated oil. The
heated oil and
the condensed steam are then allowed to drain by gravity toward the production
well. The
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well is then put on production for an extended duration, from about 7-20
months, about 9-18
months or about 11-16 months or until such time the oil recovery falls below
the cut-off
value.
[0013] A low
steam to oil mixture reduces the volume of steam injection per cycle.
Further the presence of non-condensable gases in the vapor phase of the steam
reduces the
partial pressure of the steam in the vapor phase. This causes the liquid phase
water to
vaporize and increase the steam quality. High quality steam is a combination
of low levels of
liquid water and high temperature. High quality steam generally has a
temperature higher
than 100 C.
[0014] If the
injected steam is of sufficiently high quality any addition of non-
condensable gas to the vapor phase likely to cause the steam to become
saturated or
superheated. This can results in two beneficial effects: (1) increased steam
voltune resulting
from a lowering of the steam partial pressure and temperature leads to
improved reservoir
conformance and (2) reduced heat loss and recovery of lost heat from the
surrounding area as
a result of the lowering of saturated steam temperature. This results in
better utilization of
the same amount of injected heat (improved thermal efficiency). The two phase
steam/gas
mixture is less prone to phase separation, results in more uniform steam
quality, enhances its
ability to heat the wellbore region by thermal conduction and promotes more
uniform
drainage of the heated oil.
[0015] Further
the injection of the combustion gases with steam results in upward
movement of gas to the formation above the injection well. As a result the
pressure at the top
of the reservoir is increased and provides a potential gradient that augment
gravity and
accelerate the downward movement of the heated oil toward the production well.
As the oil
drains downward, the raising gas fills the space of the vacated oil and
accumulates at the top.
As a result, a thin layer of gas accumulates at the top of the reservoir and
tended to spread
laterally along the top of the reservoir as the process continues. The
accumulated gas acts as
an insulator and reduces the heat loss to the overburden. Also the counter-
current flow of the
rising gas to falling liquid increase the contact area for mass transfer and
cause the steam to
spread aerially and improve the reservoir sweep. Lower heat losses result in
significant oil
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viscosity reduction and more mobile oil. Thus lower steam requirement, better
heat
utilization, and more mobile oil together the use of added soak time and
longer production
duration allow gravity drainage as the dominant oil recovery mechanism
contribute to very
high oil recovery and significant reduction in steam to oil ratio. The current
method is able
to produce steam oil ratios between 0.1 to 1.2, in a preferred embodiment the
current method
produces steam oil ratios between 0.2 to 0.8.
[0016] Table 1 - Summary of DownHole Steam Generation (DHSG) versus Surface
Steam Generation (SSG)
1 2
Steam Source SSG DHSG
Steam Quality 0.9 0.9
(Steam oil ratio)
Cumulative 2.2 2.4
Recovery
Millions Barrels
Oil Recovery as 44.6 48.6
% Original Oil in
Place
[0017] Table 1 summarizes selected SAGD runs conducted to investigate the
effect of
reservoir and operation parameters on the process performance. The table
demonstrates that
even though run 1 (performed with SSG) outputs similar steam quality as run 2
(performed
with DHSG), the amount of steam recovered is significantly lower. This is due
to the loss of
steam quality as it traverses the well towards the stratum. By placing a steam
generator
downhole higher quality steam can penetrate the stratum
[0018] Table 2¨ Summary of
steam quality in relation to oil recovery
1 2 3
Steam Source DHSG DHSG DHSG
Steam Quality 0.9 0.7 0.5
(Steam oil ratio) ,
Cumulative 2.2 1.7 1.4
Recovery
Millions Barrels
Oil Recovery as 44.6 34.5 28.4
% Original Oil in
Place
% Heat Returned 37.2 49 55
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to Surface from
Injection
[00191 Table 2
summarizes that oil recovery and the thermal efficiency of the SAGD
process as measured by the cumulative steam oil ratio are sensitive to steam
quality. A
negative variation of steam quality lowers the cumulative recovery of oil and
increases the
percent of heat that is returned to the surface. This is because lower quality
steam contains
less latent heat than high quality steam. Since a typical SAGD oil recovery
depends only on
the available latent heat the recovery reflects the influence of the injected
steam quality.
[0020] Table 3 ¨
Summary of DownHole Steam Generation (DHSG) versus Surface
Steam Generation (SSG) Cyclic Steam Stimulation (CSS) performance between a
single well
and two wells
SSG¨One SSG¨Two DHSG - One DHSG ¨ Two
Well Wells Well Wells
Steam Quality 0.9 0.9 0.9 0.9
Primary 0.07 0.07 0.07 0.07
Recovery in
millions of
barrels
Primary 1.34 1.34 1.34 1.34
Recovery as %
Original Oil in
Place
15 Year 2.0 2.9 2.06 2.93
Recovery in
millions of
barrels
15 Year 40 57 40 58
Recovery as %
Original Oil in
Place
Cumulative 0.7 0.5 0.6 0.4
Steam Oil Ratio
% Heat Returned 51.6 24.3 50.8 24.1
to Surface from
Injection
[00211 Table 3
summarizes the both the improvement of utilizing two wells for a CSS
performance and the benefits of using a down hole steam generator. Table 3
also shows how
although primary recovery is identical for the SSG one well and two wells as
compared to
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DHSG one well and two wells. The difference is shown during the long term
recovery of the
oil wherein an increase in the amount of oil recovered is shown. Additionally
lower
cumulative steam oil ratio's and lower % heat returned to surface can be shown
from this
table.
100221 Figure 1 depicts a steam generator placed downhole in the injection
well. In this
figure the downhole steam generator 2 is placed in the tubing 8 of the
vertical section of the
injection well 4. A typical three coil tubing bundle 6 is used to provide the
air, water and
natural gas needed to the downhole steam generator 2. Steam generated from the
downhole
steam generator 2 is flowed towards the horizontal portion of the injection
well 12 by
travelling along the vertical section of the injection well 4.
[0023] Figure 2 depicts a steam generator placed along the horizontal
portion of the
injection well. In this figure the downhole steam generator 14 is placed in
the tubing 20 of
the horizontal portion of the injection well 24. A typical three coil tubing
bundle 18 is used
to provide the air, water and natural gas needed to operate the downhole steam
generator 14.
In this depiction, the steam generated from the downhole steam generator 14
does not have to
flow through the vertical section of the injection well 16 and instead
directly injected into the
horizontal portion of the injection well 24.
[00241 Figure 3 depicts a typical SAGD process. In the SAGD process, two
parallel
horizontal oil wells are drilled in the formation, one about 4 to 6 meters
above the other. The
upper well injects steam, possibly mixed with solvents, and the lower one
collects the heated
crude oil or bitumen that flows out of the formation, along with any water
from the
condensation of injected steam. The basis of the process is that the injected
steam forms a
"steam chamber" that grows vertically and horizontally in the formation. The
heat from the
steam reduces the viscosity of the heavy crude oil or bitumen which allows it
to flow down
into the lower wellbore. The steam and gases rise because of their low density
compared to
the heavy crude oil below, ensuring that steam is not produced at the lower
production well.
The gases released, which include methane, carbon dioxide, and usually some
hydrogen
sulfide, tend to rise in the steam chamber, filling the void space left by the
oil and, to a
certain extent, forming an insulating heat blanket above the steam. Oil and
water flow is by a
countercurrent, gravity driven drainage into the lower well bore. The
condensed water and
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crude oil or bitumen is recovered to the surface by pumps such as progressive
cavity pumps
that work well for moving high-viscosity fluids with suspended solids.
[0025] Figure 4 depicts a typical CSS process. CSS consists of a single
vertical well
performing three main steps: injection, soaking and production. Steam is first
injected into a
well for a certain amount of time to heat the oil in the surrounding reservoir
to a temperature
at which it flows. After it is decided enough steam has been injected, the
steam is usually left
to "soak" for some time after (typically not more than a few days). Then oil
is produced out
of the same well, at first by natural flow (since the steam injection will
have increased the
reservoir pressure) and then by artificial lift. Production will decrease as
the oil cools down,
and once production reaches an economically determined level the steps are
repeated again.
This process can be quite effective, especially in the first few cycles.
However, it is typically
only able to recover approximately 20% of the original oil in place.
[0026] Figure 5 depicts the present oil recovery process. This process
utilizes two
parallel horizontal wells similar to SAGD, combined with the three main steps
of CSS:
injection, soaking and production while further improving typical SAGD and CSS
production
by placing the steam generator in the horizontal portion of the injection
well. The method
begins by injecting steam from a steam generator into a horizontal portion of
an injection
well. The stratum is then soaked with the steam from the injection well for a
predetermined
period of time. Heavy oil is then produced from the stratum with a production
well. In this
depiction the depth of a horizontal portion of the production well is below
the horizontal
portion of the injection well and the position of the steam generator is
placed along the
horizontal portion of the injection well.
[0027] The preferred embodiment of the present invention has been disclosed
and illustrated. 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. The
scope of the claims should not be limited by the preferred embodiments set
forth in the
examples, but should be given the broadest interpretation consistent with the
description as a
whole.
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