Note: Descriptions are shown in the official language in which they were submitted.
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Mobil Case No. 78175
VISICOUS OIL RECOVERY OSING STEAM IN HORIZONTAL WELL
DESCRIPTION
1. Technical Field
The present invention relates to a process for
the recovery of highly viscous oil or hydrocarbons from
subterranean reservoirs or formations and in one of its
aspects relates to a process for recovering heavy
hydrocarbons by injecting steam into a horizontal well
within a subterranean formation, closing in the well for a
"soak period", and then producing the well while
continuously injecting steam into the horizontal well.
2. Background of the Invention
World energy supplies are substantiallv impacted
by the world's heavy oil resources. It has been estimated
that heavy oil may comprise as much as approximately 2,100
billion barrels of the world's total oil reserves.
Therefore, processes for economically recovering oil from
these viscous reserves are of extreme importance.
Asphalt, tar, and heavy oil are typically
deposited near the surface with overburden depths that
span a few feet to a few thousands of feet. In Canada,
vast deposits of heavy oil are found in the Athabasca,
Cold Lake, Celtic, Lloydminster and McMurray reservoirs.
In California, heavy oil is found in the South Belridge,
Midway Sunset, Kern River and other reservoirs.
In large Athabasca and Cold Lake bitumen
deposits, oil is essentially immobile, i.e. unable to flow
under normal natural drive, primary recovery mechanisms.
Furthermore, oil saturations in these formations are
typically large. This normally limits the injectivity of
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a fluid (heated or cold) into the formation. Moreover,
many of these deposits are too deep below the surface to
be mined effectively and/or economically.
In-situ techniaues of recovering viscous oil and
bitumen have been the subject of much previous
investigation. These techniques can be split into three
categories: (1) cyclic processes involving injecting and
producing a viscosity reducing agent: (2) continuous
steaming processes which involve injecting a heated fluid
at one well and displacing oil to a distant well(s): and
(3) the relatively new Steam (or Solvent) Assisted Gravity
Drainage process.
Each of these techniques have substantial
limitations when used in the ecomonic recovery of very
viscous hydrocarbons, e.g. those present in reservoirs
such as Athabasca or Cold Lake. That is, cyclic steam or
solvent stimulation in reservoirs such as these is
severely hampered due to the fact that the injectivity of
steam and/or solvent into this type of producing
formations is very low. Some success with a fracturing
technique has been obtained in the some reservoirs where
there is no significant underlying water aquifer.
However, if a water aquifer exists beneath the oil bearing
formaton, fracturing during steam injection usually
results in an early and large water influx during the
production phase.
Also, with fracturing, it is very difficult to
confine steam within the desired portion of the
reservoir. These factors substantially lower the economic
performance of such wells. In addition, cyclic steaming
techniques are not continuous thereby reducing the
economic W ability of the process. Clearly, these steam
stimulation techniques in tight, heavy oil reservoirs
appear limited.
Similar to cyclic steaming, continuous steam
drive processes carried out in vertical wells are not
technically or economically .feasible in many of these very
viscous, bitumen-type reservoirs. The mobility of the oil
is simply far too small to allow the oil to flow from a
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cold production well as it does in other types of
reservoirs. Injecting steam into one well and producing
from an adjacent well is not practical unless a fracture
is first formed in the producing formation. As will be
understood in the art, fracturing between wells is very
difficult to control. Hence, there are considerable
operationing problems in attempting to use classical steam
flooding in these heavy oil reservoirs.
Steam Assisted Gravity Drainage (SAGD) is
disclosed in U.S. Patent 4,344,485 which issued to Butler
in 1982. SAGD uses a pair of horizontal wells conneced by
a vertical fracture. The process has several advantages
over most steam stimulation or continuous steam injection
processes. One advantage is that initial steam
injectivity is not needed as steam rises by gravity above
the upper well thereby replacing oil produced at the lower
well. Another advantage is that since the process is
gravity dominated and steam replaces produced oil, good
sweep efficiency is obtained. Yet another advantage is
since horizontal wells are utilized, good oil rates may be
obtained by simply extending the len4th of the well to
contact more of the oil bearing formation. In the SAGD
process, steam is injected in the upper horizontal well
while oil and water are produced through the lower
horizontal well. Steam production from the lower well is
controlled so that the entire process remains in the
gravity dominated regime. A steam chamber rises above the
upper well and oil warmed by conduction drains along the
outside of the chamber to the lower production well.
This process appears to have the advantages of
high oil rates and good overall recovery. Also, it can be
used in the absence of a vertical fracture. However, one
serious limitation of this process in practical
application is the need to have two parallel horizontal
wells - one beneath the other. Those skilled in the art
of drilling horizontal wells will recognize the difficulty
in drilling relatively long, parallel horizontal wells,
one above the other, especially with any real accuracy in
thin formations.
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Other heavy oil recovery processes have also been
proposed in which only a single, horizontal well is
used. For example in US Patents 5,148,869 (Sanchez) and
5,215,149 (Lu), both use a single horizontal wellbore to
inject steam through one flowpath while producing the
heated heavy oil from a second flowpath. The steam
injection is continuous but the region of the formation
which undergoes heating is limited to a relatively small
region surrounding the wellbore since the steam can not
readily penetrate into the formation and must heat the
contacted foramtion primarily by conduction. The same is
implied in the paper: "Steam Circulation in Horizsntal
Wellbores", D.A. Best et al, SPE/DOE 20203, presented in
Tulsa, OK, April 22-25, 1990.
Another recovery process of this type is one
wherein steam is injected into a single horizontal
wellbore to initially heat a heavy oil formation around
the wellbore. The well is then shut-in and the formation
is allowed to "soak"; see US Patent 4,116,275 (Bulter et
al. ) . This allows the steam to heat a. greater region of
the formation since the steam now heats by convection as
well as conduction. However, in known prior-art processes
of this type, the well is merely opened after the soak
period and is allowed to produce until the well is "drawn
down"; i.e. the bottomhole pressure drops below an
acceptable level for production. Even though the steam
and shut-in cycles may be repeated, the well has a
tendence to cool down during each production cycle which,
in turn, results in the thickening of the heated oil (i.e.
the viscosity of the oil increases as it cools) thereby
requiring more steam and longer injection intervals during
each cycle to raise the bottomhole temperatures and
pressures back to those desired for the soak period.
SUMMARY OF THE INVEDITION
The present invention provides a method for
recovering viscous oil from a subterranean formation
through a wellbore having a substantially horizontal
section into the formation. The formation is initially
heated by injecting steam into the horizontal section and
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circulating it back to the surface. This initial heatincr
reduces the viscosity of the oil in the formation
surrounding the wellbore so that the oil will flow into
the horizontal section and will be produced to the surface
with the circulating steam. Where steam circulation
cannot be initiated without risking the fracturing of the
formation, a pump may be used to produce the infected
steam.
At the end of the initial heating period,
production from the wellbore is ceased and the injection
of steam is continued until a slug of steam is accumulated
within and around the horizontal section of the well.
Steam injection is then ceased and the well is allowed to
"soak" for a period of time after which, first production
and then steam injection are resumed. By continuously
injecting steam while the well is being produced, the well
is not "drawn down" as rapidly as is the case in ~tior art
processes of this type.
When the oil in the produced fluids drops below
an acceptable level, the production is ceased and a slug
of steam is again allowed to build-up in the well after
which the well is closed-in for another soak period. At
the end of this soak period, production and the injection
of steam are again resumed as before. This cycle is
repeated until the production of oil drops below an
economical recovery rate.
More specifically, in accordance with the present
invention, highly viscous oil is recovered from a
subterranean formation using a single, horizontal wellbore
which is subjected to steam stimulation. First, a
wellbore is drilled to penetrate the formation which has a
substantially vertical section extending from the surface
and a contiguous substantially horizontal section
extending into the formation. The vertical section is
cased and the horizontal section is preferably completed
with a slotted liner or the like. After the wellbore is
completed, steam is continuously circulated in and out of
the horizontal wellbore at a pressure below the
formation's fracture pressure thereby heating the
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formation surrounding the horizontal wellbore by
conduction to reduce the viscosity of the viscous oil.
This enables the heated oil to drain into the wellbore and
thereby create voidage in the formation around - primarily
above - the wellbore.
This step is continued until the temperature of
the horizontal welbore reaches the saturation temperature
of steam at the horizontatl wellbore pressure.
Thereafter, the production is ceased and a slug of steam
is injected and accumulated in and around the horizontal
section, still at a pressure below the formation's
fracture pressure. The well is then shut-in and is
allowed to soak for a period of time, preferably from 1 to
7 days. After the soak period, the well is then opened
for production and the continuous injection of steam is
resumed soon after oil appears in the produced fluids;
i.e. 20 to 30~ of the injected steam may have' to be
produced before any substantial oil shows up in the
produced fluids. The steam is again injected at a
pressure below the formation's fracture pressure. This
step is continued until the oil in the produced fluids
becomes unfavorable.
The sequence of injecting a slug of steam, soak
period, and production and steam injection is repeated for
a plurality of cycles until the rate of oil recovery
becomes unfavorable. As the number of cycles increases,
the size of each successive steam slug and respective soak
period also increases. In some instances, the production
of oil may also be assisted by pumping the produced fluids
to the surface through the production tubing.
BRIEF DESCRIPTIOr' OF THE DRAWING
The actual construction, operation, and apparent
advantages of the present invention will be better
understood by referring to Figure 1. not necessarily to
scale, which is a schematic, sectional view of a
horizontal well utilized in carrying out the process of
the present invention.
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BEST KNOWN MODE FOR CARR~'ING OUT THE INVENTION
This invention is directed to a cyclic, steam
stimulation method for removing immobile or highly viscous
oil from a formation or reservoir through a horizontal
well which penetrates into the formation. Referring to
Figure 1. the drawing illustrates a subterranean
formation or reservoir 10 which contains a highly viscous
oil and which lies below the earth's surface 12 beneath
overburden 14. A well bore 16 having a substantial
vertical section 18 and a contiguous substantially
horizontal section 20 has been drilled to penetrate the
formation 10 and to extend therein.
The wellbore 16 is cased down substantially to
the beginning of the horizontal wellbore 20. The
substantial length of the horizontal wellbore section 20
is lined with a liner 22 which, in turn, has slots 24
along its length. The horizontal wellbore '20 and
surrounding formation are in fluid communication through
slots 24. An injection tubing 26 is run inside the
wellbore 16 from the surface to the far end of the slotted
liner 22. The whole or part of injection tubing 26 is
insulated to ensure that the quality of the injected steam
exiting at the end of the tubing is as high as possible.
A production tubing 28 is run between the
wellbore 16 and the injection tubing 26 form the surface
to the lower end of the vertical section 18 of the
wellbore. The annular space 30 between the vertical
wellbore casing and the injection/production tubin_qs may
be filled with an inert gas, preferably nitrogen= The
nitrogen blanket serves three manor purposes: (1) it
reduces heat losses to the overburden for better thermal
efficiency and casing protection, (2) it initiates steam-
lift production mechanism after flow-back, and (3) it
provides a medium through which downhole (i.e. bottomhole)
pressure can be measured at the surface. The appropriate
gauges (not shown) can be provided at the surface in
communication with the well annulus 30 to directly monitor
both the bottomhole temperature and pressure as will be
understood in the art.
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After the well has been completed, formation 10
is initially conditioned or heated by continuously
circulating steam down the well and into and out of the
horizontal wellbore 20 at a pressure below the formation's
fracture pressure and for a time sufficient to heat the
formation surrounding the horizontal wellbore by transient
conduction. It is important not to fracture the formation
because once fractured, most of the injected steam will
flow into the fracture thereby making it very difficult to
heat the formation along the length of the horizontal
wellbore. While circulating steam during this first step,
the steam injection pressure and the steam circulation
rate (hence, the bottomhole pressure) can be controlled by
adjusting chokes or the like (not shown) which, in turn,
are positioned in injection tubing 26 at the surface.
The steam circulates down and out the far end of
the tubing 26 and back through annulus annulus 32 between
tubing 26 and liner 22 and then up to the surface through
production tubing 28. The inert gas blanket in vertical
annulus 30 prevents the steam from flowing up through the
annulus 30. As the steam circulates within the horizontal
wellbore 20, the slots 24 in liner 22 allow the steam to
contact formation 10 to thereby heat the formation by
transient conduction. Since the steam is being injected
below the fracture pressure of formation 10 and since
there is little voidage within formation 10 during this
initial heating step, there will be no substantial
penetration of the steam into the formation.
As a relatively small region of the formation 10
surrounding horizontal wellbore 20 heats up, the viscosity
of the heavy oil in this region is reduced whereby the now
less-viscous oil drains by gravity into the horizontal
wellbore 20 through slots 24 in liner 22. This drainage
of oil alon4 with the ever present connate water from the
pore spaces in formation 10 begins to create voidage
within the formation. Once voidage has been created in
the formation, the second step of_ the present invention
can then be carried out; i.e. injection of a slug of steam
after which the well is closed-in to allow the formation
to "soak" for a period of time.
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The first step, i.e. conditioning of the
formation to initially heat the formation and thereby
create voidave therein, is considered complete when the
temperature within the horizontal wellbore 20 reaches the
saturation temperature of the steam at horizontal wellbore
pressure as measured at the surface through annulus 30.
Another good indicator that the first step is complete is
when the returned fluids (produced steam through
production tubing 28) contains substantial amounts of
produced oil. This first step of heating the formation
can typically take from about 20 to 100 days or longer,
depending on well and/or formation parameters, injection
and production pressures, steam quality, circulation
rates, etc..
After the formation 10 surrounding horizontal
wellbore 20 has been conditioned (i.e. heated) and some
voidage has been created in the formation, the production
tubing 28 is closed and the injection of steam is
continued through injection tubing 26. This injected
steam which now has no way to return to the surface,
accumulates as a "slug" within and around horizontal
wellbore 20. Injection of steam continues until the
bottomhole pressure in wellbore 20 approaches (i.e. nearly
equals) the fracture pressure of formation 10. At this
time, the injection of steam is ceased and the well is
shut-in and the formation is allowed to "soak" for a
period of time. Allowing the formation to soak results in
heat being transferred from the steam by connective
heating in addition to conductive heating. Heat transfer
due to connective heating normally increases the effective
thermal conductivity from the steam to the formation by as
much as approximately 4 to 6 times over that which results
from conduction heating alone. This results in the heated
region surrounding the horizontal wellbore to extend
further out into the formation and heat the additional oil
therein.
The well remains shut-in for a defined soak
period; e.g. from 1 to 7 days or longer dependinct on the
particular field conditions involved, after which the
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production tubing 28 is opened and the well is again
produced. In accordance with the present invention, soon
after the production tubing 28 is opened for production,
the continuous injection of steam is restarted through
injection tubing 26. Continuous injection of steam starts
when the wll starts producing oil, which may typically
occur after from about 20 to 30$ of the injected steam has
been produced. This continuous injection of steam during
the production following a soak period performs at least
two important functions.
First, it helps to maintain the produced oil at
its reduced viscosity by keeping it warm in and around the
wellbore, thereby allowing the oil to flow to the surface
without any substantially cooling, hence thickening,
within the production tubing. Second, and at least
equally as importantly, the bottomhole pressure in the
well is not "drawn-down" substantially dur2ng the
production step. That is, in typical "huff and puff" or
similar steam operations, the well is merely opened after
a soak period and the steam and produced fluids flow to
the surface under the influence of the relatively high
bottomhole pressure. Production is continued until the
bottomhole pressure drops below an acceptable value at
which time another slug of steam is injected, the well
shut-in, and the soak and production cycles are repeated.
In the present invention, by continuously
injecting live steam during the production step, neither
the bottomhole pressure nor the temperature in the
horizontal wellbore 20 will drop substantially. The
pressure at which the steam is injected during the
production step still should be below the fracturing
pressure of formation 10 just as it was for the initial
heating step.
Although the steam injected during production
continues to carry heat to the horizontal wellbore 20,
this heat will not result in any significant extension of
the heated region within the formation since it is only
heating by conduction. Accordingly, once substantially
all of the oil from the previously heated region has
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flowed into wellbore 20, the oil in the production fluids
will drop below an acceptable level. At this time,
production tubing 28 is again closed and steam injection
is continued until a slug of steam is accumulated within
horizontal wellbore 20 as described above. The injection
of steam is then ceased and the well is shut-in and
allowed to soak for a second period after which it is
reopened for production and injection of steam as
described above. This cycle is repeated until
substantially all of the oil which can be economically
recovered has been produced.
As the cycles are repeated, a larger and larger
region around wellbore 20 will be heated from which oil
will drain into the wellbore. This creates a larger and
larger voidage within the formation which, in turn,
requires respective larger slugs of steam for each
successive cycle. Further, since larger regions are being
effected with each successive cycle, the length of the
soak cycle will also increase. The actual size of any
successive steam slug and/or the actual length of a
respective soak period will depend upon the
characteristics and conditions existing in a particular
field operation.
Although steam is injected below the fracture
pressure of the producing formation, some degree of local
failure of sand in shear (dilation) takes place and is
advantageous to the process as it facilitates the entering
of steam into the formation, thus resulting in connective
heating. Further, on a cyclic basis, the cold water
equivalent of total injected fluids equals the total
produced fluids, thus maintaining the average reservoir
pressure at or near its original valve. This is a very
important part of this process and results in higher
recoveries of oil over those achievable by "huff and puff"
or steam circulation alone. It is preferred that the
steam quality be as high as possible to provide maximum
heat to the formation and thereby increase oil
production. Preferably, the steam is of at least 80$
quality.
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In another embodiment of the present invention,
it may become desirable or necessary to pump the produced
fluids to the surface rather than allowing the fluids to
flow to the surface due to the circulation of the steam.
In such a modification, a pump (not shown) will be placed
at or near the lower end of production tubing 28 to pick
up the produced fluids and pump them to the surface
through the production tubing.
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