U.S. patent application number 15/140136 was filed with the patent office on 2016-10-27 for sw-sagd with between heel and toe injection.
The applicant listed for this patent is CONOCOPHILLIPS COMPANY. Invention is credited to Qing CHEN, Wendell P. MENARD.
Application Number | 20160312592 15/140136 |
Document ID | / |
Family ID | 57147460 |
Filed Date | 2016-10-27 |
United States Patent
Application |
20160312592 |
Kind Code |
A1 |
CHEN; Qing ; et al. |
October 27, 2016 |
SW-SAGD WITH BETWEEN HEEL AND TOE INJECTION
Abstract
The present disclosure relates to a particularly effective well
configuration that can be used for single well steam assisted
gravity drainage (SW-SAGD), wherein steam injection occurs at one
or more points between the heel and toe, instead of at the toe as
in the prior art.
Inventors: |
CHEN; Qing; (Houston,
TX) ; MENARD; Wendell P.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
CONOCOPHILLIPS COMPANY |
Houston |
TX |
US |
|
|
Family ID: |
57147460 |
Appl. No.: |
15/140136 |
Filed: |
April 27, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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62153269 |
Apr 27, 2015 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 17/203 20130101;
E21B 43/2406 20130101; E21B 43/162 20130101; E21B 33/12 20130101;
E21B 43/305 20130101 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 33/12 20060101 E21B033/12; E21B 17/20 20060101
E21B017/20; E21B 43/30 20060101 E21B043/30 |
Claims
1) A method of producing heavy oils from a reservoir by single well
steam and gravity drainage (SW-SAGD), comprising: a) providing a
horizontal well below a surface of a reservoir; b) said horizontal
well having a toe end and a heel end and a middle therebetween; c)
injecting steam into one or more injection points between said toe
end and said heel end; and d) simultaneously producing mobilized
heavy oil; e) wherein said method produces more oil at a time point
than a similar SW-SAGD well with steam injection only at said
toe.
2) The method of claim 1, wherein each injection point is separated
from a production segment by at least two thermal packers.
3) The method of claim 1, wherein an injection point is at said
middle.
4) The method of claim 1, wherein two injection points are at about
1/4 and 3/4 of a horizontal length of said well.
5) The method of claim 1, wherein injected steam includes
solvent.
6) The method of claim 1, wherein said method includes a preheating
phase wherein steam is injected along the entire length of the
well.
7) The method of claim 1, wherein said method includes a cyclic
preheating phase comprising a steam injection period along the
entire length of the well followed by a soaking period.
8) The method of claim 7, including two cyclic preheating
phases.
9) The method of claim 7, including three cyclic preheating
phases.
10) The method of claim 1, wherein said method includes a
pre-heating phase comprising a steam injection in both the
injection segment and the production segment followed by a soaking
period.
11) The method of claim 10, including two cyclic pre-heating
phases.
12) The method of claim 10, including three cyclic pre-heating
phases.
13) The method of claim 7, wherein said soaking period is 10-30
days.
14) The method of claim 7, wherein said soaking period is 20
days.
15) A well configuration for producing heavy oils from a reservoir
by single well steam and gravity drainage (SW-SAGD), comprising: a)
a horizontal well in a subsurface reservoir; b) said horizontal
well having a toe end and a heel end and having at least three
segments comprising: i) at least two production segments bracketing
at least one injection segment; ii) said production segments fitted
for production; and iii) said injection segments fitted for
injection.
16) The well configuration of claim 15, wherein thermal packers
separate said injection segments and said production segments.
17) The well configuration of claim 15, comprising two injection
segments bracketed by production segments.
18) The well configuration of claim 16, wherein said two injection
segments are at about 1/4 and 3/4 of an overall well length.
19) The well configuration of claim 17, said at least two injection
segments fitted with coiled tubing having two orifices to inject
steam into said two injection segments.
20) The well configuration of claim 15, comprising three injection
segments bracketed by production segments.
21) An improved method of producing heavy oils from a SW-SAGD,
wherein steam is injected into a toe end of a horizontal well to
mobilize oil which is simultaneously produced at a heel end of said
horizontal well, the improvement comprising providing one or more
injection points for steam between said heel end and said toe end
during a production phase, thus improving a CSOR of said horizontal
well at a time period as compared to a similar well with steam
injection only at said toe end during said production phase.
Description
PRIORITY CLAIM
[0001] This application is a non-provisional application which
claims benefit under 35 USC .sctn.119(e) to U.S. Provisional
Application Ser. No. 62/153,269 filed Apr. 27, 2015, entitled
"SW-SAGD WITH BETWEEN HEEL AND TOE INJECTION," which is
incorporated herein in its entirety.
FEDERALLY SPONSORED RESEARCH STATEMENT
[0002] Not Applicable.
REFERENCE TO MICROFICHE APPENDIX
[0003] Not applicable.
FIELD OF THE DISCLOSURE
[0004] This disclosure relates generally to methods that can
advantageously produce oil using steam-based mobilizing techniques.
In particular, it relates to improved single well gravity drainage
techniques with better steam chamber development than previously
available.
BACKGROUND OF THE DISCLOSURE
[0005] Oil sands are a type of unconventional petroleum deposit,
containing naturally occurring mixtures of sand, clay, water, and a
dense and extremely viscous form of petroleum technically referred
to as "bitumen," but which may also be called heavy oil or tar.
Bitumen is so heavy and viscous (thick) that it will not flow
unless heated or diluted with lighter hydrocarbons. At room
temperature, bitumen is much like cold molasses, and the viscosity
can be in excess of 1,000,000 cP.
[0006] Due to their high viscosity, these heavy oils are hard to
mobilize, and they generally must be heated in order to produce and
transport them. One common way to heat bitumen is by injecting
steam into the reservoir. Steam Assisted Gravity Drainage or "SAGD"
is the most extensively used technique for in situ recovery of
bitumen resources in the McMurray Formation in the Alberta Oil
Sands.
[0007] In a typical SAGD process, two horizontal wells are stacked
one over the other and vertically spaced by 4 to 10 meters (m). See
FIG. 1. The production well is located near the bottom of the pay
and the steam injection well is located directly above and parallel
to the production well. Steam is injected continuously into the
injection well, where it rises in the reservoir and forms a steam
chamber. With continuous steam injection, the steam chamber will
continue to grow upward and laterally into the surrounding
formation. At the interface between the steam chamber and cold oil,
steam condenses and heat is transferred to the surrounding oil.
This heated oil becomes mobile and drains, together with the
condensed water from the steam, into the production well due to
gravity segregation within steam chamber.
[0008] The use of gravity gives SAGD an advantage over conventional
steam injection methods. SAGD employs gravity as the driving force
and the heated oil remains warm and movable when flowing toward the
production well. In contrast, conventional steam injection
displaces oil to a cold area, where its viscosity increases and the
oil mobility is again reduced.
[0009] Although quite successful, SAGD does require large amounts
of water in order to generate a barrel of oil. Some estimates
provide that 1 barrel of oil from the Athabasca oil sands requires
on average 2 to 3 barrels of water, and it can be much higher,
although with recycling the total amount can be reduced. In
addition to using a precious resource, additional costs are added
to convert those barrels of water to high quality steam for
down-hole injection. Therefore, any technology that can reduce
water or steam consumption has the potential to have significant
positive environmental and cost impacts.
[0010] Additionally, SAGD is less useful in thin stacked pay-zones,
because thin layers of impermeable rock in the reservoir can block
the expansion of the steam chamber leaving only thin zones
accessible, thus leaving the oil in other layers behind. Further,
the wells need a vertical separation of about 4-5 meters in order
to maintain the steam trap. In wells that are closer, live steam
can break through to the producer well, resulting in enlarged slots
that permit significant sand entry, well shutdown and damage to
equipment.
[0011] Indeed, in a paper by Shin & Polikar (2005), the authors
simulated reservoir conditions to determine which reservoirs could
be economically exploited. The simulation results showed that for
Cold Lake-type reservoirs, a net pay thickness of at least 20
meters was required for an economic SAGD implementation. A net pay
thickness of 15 m was still economic for the shallow Athabasca-type
reservoirs because of the high permeability of this type of
reservoir, despite the very high bitumen viscosity at reservoir
conditions. In Peace River-type reservoirs, net pay thicker than 30
meters was expected to be required for a successful SAGD
performance due to the low permeability of this type of reservoir.
The results of the study indicate that the shallow Athabasca-type
reservoir, which is thick with high permeability (high k.times.h),
is a good candidate for SAGD application, whereas Cold Lake and
Peace River-type reservoirs, which are thin with low permeability,
are not as good candidates for conventional SAGD
implementation.
[0012] In order to address the thin payzone issue, some petroleum
engineers have proposed a single wellbore steam assisted gravity
drainage or "SW-SAGD." See e.g., FIG. 2A. In SW-SAGD, a horizontal
well is completed and assumes the role of both injector and
producer. In a typical case, steam is injected at the toe of the
well, while hot reservoir fluids are produced at the heel of the
well, and a thermal packer is used to isolate steam injection from
fluid production (FIG. 2A).
[0013] Another version of SW-SAGD uses no packers, simply tubing to
segregate flow. Steam is injected at the end of the horizontal well
(toe) through an isolated concentric coiled tubing (ICCT) with
numerous orifices. In FIG. 2B a portion of the injected steam and
the condensed hot water returns through the annulus to the well's
vertical section (heel). The remaining steam, grows vertically,
forming a chamber that expands toward the heel, heating the oil,
lowering its viscosity and draining it down the well's annular by
gravity, where it is pumped up to the surface through a second
tubing string.
[0014] Advantages of SW-SAGD might include cost savings in drilling
and completion and utility in relatively thin reservoirs where it
is not possible to drill two vertically spaced horizontal wells.
Basically since there is only one well, instead of a well pair,
start up costs are only half that of conventional SAGD. However,
the process is technically challenging and the method seems to
require even more steam than conventional SAGD.
[0015] Field tests of SW-SAGD are not extensively documented in the
literature, but the available evidence suggests that there is
considerable room to optimize the SW-SAGD process.
[0016] For example, Falk overviewed the completion strategy and
some typical results for a project in the Cactus Lake Field,
Alberta Canada. A roughly 850 m long well was installed in a region
with 12 to 16 m of net pay to produce 12.degree. API gravity oil.
The reservoir contained clean, unconsolidated, sand with 3400 and
permeability. Apparently, no attempts were made to preheat the
reservoir before initiation of SW-SAGD. Steam was injected at the
toe of the well and oil produced at the heel. Oil production
response to steam was slow, but gradually increased to more than
100 m.sup.3/d. The cumulative steam-oil ratio was between 1 and 1.5
for the roughly 6 months of reported data.
[0017] McCormack also described operating experience with nineteen
SW-SAGD installations. Performance for approximately two years of
production was mixed. Of their seven pilot projects, five were
either suspended or converted to other production techniques
because of poor production. Positive results were seen in fields
with relatively high reservoir pressure, relatively low oil
viscosity, significant primary production by heavy-oil solution gas
drive, and/or insignificant bottom-water drive. Poor results were
seen in fields with high initial oil viscosity, strong bottom-water
drive, and/or sand production problems. Although the authors noted
that the production mechanism was not clearly understood, they
suspected that the mechanism was a mixture of gravity drainage,
increased primary recovery because of near-wellbore heating via
conduction, and hot water induced drive/drainage.
[0018] Moriera (2007) simulated SW-SAGD using CMG-STARS, attempting
to improve the method by adding a pre-heating phase to accelerate
the entrance of steam into the formation, before beginning a
traditional SW-SAGD process. Two processes were modeled, as well as
conventional SW-SAGD and dual well SAGD. The improved processes
tested were 1) Cyclic injection-soaking-production repeated three
times (20, 10 and 30 days for injection, soaking and production
respectively), and 2) Cyclic injection repeated three times as in
1), but with the well divided into two portions by a packer, where
preheat steam was injected at the toe and center and circulated
throughout the well, but production occurring only in the producing
heel half with toe steam injection.
[0019] They found that the cyclical preheat period provided better
heat distribution in the reservoir and reduces the required
injection pressure, although, it increased the waiting time for the
continuous injection process. Additionally, the division of the
well by a packer and the injection of the steam in two points, in
the middle and at the extremity of the well, helped the
distribution of the heat in the formation and favor oil recovery in
the cyclical injection phase. They also found that in the
continuous injection phase, the division of the well induces an
increase of the volume of the steam chamber, and improved the oil
recovery in relation to the SW-SAGD process. Also, an increase of
the blind interval (blank pipe), between the injection and
production passages, increased the difference of the pressure and
drives the displaced oil in the injection section into the
production area, but caused imprisonment of the oil in the
injection section, reducing the recovery factor.
[0020] Overall, the authors concluded that modifications in SW-SAGD
operation strategies can lead to better recovery factors and oil
steam ratios than those obtained with the DW-SAGD process, but that
SW-SAGD performance was highly variable.
[0021] It is noted that these authors did use central (and toe)
injection during the preheat or startup phase. However, the steam
was allowed to travel the length of the well, thus the entire well
was preheated. Further, actual production phase was the same as
usual, with toe injection and heel production. Since the steam is
injected at the toe segment, it is expected that the oil from the
steam end, at least part of it, will not be recoverable.
[0022] Although beneficial, the SW-SAGD methodology could be
further developed to further improve its cost effectiveness. This
application addresses some of those needed improvements.
SUMMARY OF THE DISCLOSURE
[0023] The conventional SW-SAGD utilizing one single horizontal
well to inject steam into reservoir through toe and produce liquid
(oil and water) through mid and heel of the well has potential for
thin-zone applications where placing two horizontal wells with 5 m
vertically apart required in the SAGD is technically and
economically challenging. SW-SAGD, however, exhibits several
disadvantages leading to slow steam chamber growth and low oil
rate.
[0024] First of all, SW-SAGD is not efficient in developing the
steam chamber. Due to the arrangement of injection and production
points in the conventional SW-SAGD, the steam chamber can grow only
in one side towards the heel. In other words, only one half of the
surface area surrounding the steam chamber is available for heating
and draining oil.
[0025] Secondly, a large portion of the horizontal well length
perforated for production does not actually contribute to oil
production until the steam chamber expands over the whole length.
This is particularly true during the early stage where only a small
portion of the well close to the toe collects oil.
[0026] This disclosure proposes instead to use variations of steam
injection point location and number to improve the recovery
performance. The essential idea of the invention is to allow full
development of steam chamber from both sides and increase the
effective production well length.
[0027] FIG. 1B shows schematically a simple, but effective (as
demonstrated later by simulation) process modified from the
conventional SW-SAGD, in which the steam injection point is placed
in the middle of the horizontal well. The toe and heel sections of
the horizontal well, isolated from the steam injection portion by
thermal packers within the wellbore, are perforated and serve as
producer wells to collect oil and condensed water.
[0028] As illustrated in FIG. 3, the steam chamber can now grow
from both sides, with the effective thermal and drainage interfaces
virtually doubled. Consequently, the effective production well
length is doubled, resulting in a significant uplift in oil
production rate. To further improve the performance SW-SAGD,
multiple steam injection points can be introduced into the wellbore
to initiate and grow a serial of steam chambers simultaneously.
[0029] FIG. 4 gives an example with two injection points, one at
1/4 well length from the heel and the other 3/4 well length from
the heel. The SW-SAGD with multiple steam injection points can
significantly accelerate the oil recovery by engaging more well
length into effective production. The number of the steam injection
points and intervals between them normally need to be determined
and optimized based on the reservoir properties and economics.
[0030] It is worth pointing out that implementing center or
multi-injection points within a single wellbore adds complexity to
the wellbore design, and consequently well cost (as compared to
standard SW-SAGD). For example, the well completion will require
packers on either side of the steam injection points, and the ICCT
will require outlets for steam if multi-point injection methods are
used. Nevertheless, the proposed invention presents a big
potential, and the increased cost is incremental as compared with
the cost of saving in injector well drilling. Further, as shown in
FIGS. 7 and 8, the increased recovery herein is a likely
game-changer for SW-SAGD applications, especially as applied to
thin-zone bitumen reservoirs.
[0031] The method is otherwise similar to SAGD, which requires
steam injection (often in both wells) to establish fluid
communication between wells (not needed here) as well as a steam
chamber. When the steam chamber is well developed, injection
proceeds in only the injectors, and production begins at the
producer. Alternatively, the startup or preheat period can be
reduced or even eliminated.
[0032] Preferably, the method includes preheat cyclic steam phases,
wherein steam is injected throughout both injector and producer
segment, for e.g. 20-50 days, then allowed to soak into the
reservoir, e.g., for 10-30 days, and this preheat phase is repeated
two or preferably three times. This ensures adequate steam chamber
growth along the length of the well.
[0033] Also preferred the steam injection can be combined with
solvent injection or non-condensable gas injection, such as
CO.sub.2, as solvent dilution and gas lift can assist in
recovery.
[0034] The invention can comprise any one or more of the following
embodiments, in any combination(s) thereof:
[0035] An improved method of producing heavy oils from a SW-SAGD,
wherein steam in injected into a toe end of a horizontal well to
mobilize oil which is then produced at a heel end of said
horizontal well, the improvement comprising providing one or more
injection points for steam between said heel end and said toe end,
thus improving a CSOR of said horizontal well at a time period as
compared to a similar well with steam injection only at said toe
end.
[0036] A method of producing heavy oils from a reservoir by single
well steam and gravity drainage (SW-SAGD), comprising: providing a
horizontal well below a surface of a reservoir; said horizontal
well having a toe end and a heel end and a middle therebetween;
injecting steam into one or more injection points between said toe
end and said heel end; and simultaneously (with said steam
injection) producing mobilized heavy oil; wherein said method
produces more oil at a time point than a similar SW-SAGD well with
steam injection only at said toe.
[0037] A well configuration for producing heavy oils from a
reservoir by single well steam and gravity drainage (SW-SAGD),
comprising: a horizontal well in a subsurface reservoir; said
horizontal well having a toe end and a heel end and having at least
three segments comprising: at least two production segments
bracketing at least one injection segment; said production segments
fitted for production; and said injection segments fitted for
injection.
[0038] A method or configuration as herein described, wherein each
injection point is separated from a production segment by at least
two thermal packers.
[0039] A method or configuration as herein described, wherein an
injection point is at said middle.
[0040] A method or configuration as herein described, wherein two
injection points are at about 1/4 and 3/4 of a horizontal length of
said well.
[0041] A method or configuration as herein described, said at least
two injection segments fitted with tubing having two orifices to
inject steam into said two injection segments.
[0042] A method as herein described, wherein production and
injection take place simultaneously.
[0043] A method as herein described wherein injected steam includes
solvent.
[0044] A method as herein described wherein said method includes a
preheating phase wherein steam is injected along the entire length
of the well.
[0045] A method or configuration as herein described wherein said
method includes a cyclic preheating phase comprising a steam
injection period along the entire length of the well followed by a
soaking period.
[0046] A method as herein described wherein said method includes a
pre-heating phase comprising a steam injection in both the
injection segment and the production segment followed by a soaking
period.
[0047] Preferably, two or three cyclic preheating phases are used.
Preferably the soaking period is 10-30 days or about 20 days.
[0048] "SW-SAGD" as used herein means that a single well serves
both injection and production purposes, but nonetheless there may
be an array of SW-SAGD wells to effectively cover a given
reservoir. This is in contrast to conventional SAGD where the
injection and production wells are separate during production
phase, necessitating a wellpair at each location.
[0049] As used herein, "preheat" or "startup" is used in a manner
consistent with the art. In SAGD the preheat stage usually means
steam injection throughout both wells until the steam chamber is
well developed and the two wells are in fluid communication. Thus,
both wells are fitted for steam injection. Later during production,
the production well is fitted for production, and steam injected
into the injector well only. In SW-SAGD, the meaning is the same,
except that there is only a single well. Thus, preheat means steam
injection throughout the well (e.g., no packers) in order to
develop a steam chamber along the entire length of the well.
[0050] As used herein, "cyclic preheat" is used in a manner
consistent with the art, wherein the steam is injected, preferably
throughout the horizontal length well, and left to soak for a
period of time, and any oil collected. Typically the process is
then repeated two or more times. Steam injection throughout the
length of the well can be achieved herein by merely removing or
opening packers, such that steam travels the length of the well,
exiting any slots or perforations used for production.
[0051] As used wherein, a "production phase" is that phase where
steam injection and production occur simultaneously, and is
understood in the art to be different from a "preheat" or "startup"
phase, where steam is injected for preheat purposes and the well
configuration is different. The invention herein relates to steam
injection during production phase that occurs at one or more
locations between the heel and toe. Since there is only a single
well, packers are typically required to separate the steam
injection and production segments so that they can occur
simultaneously.
[0052] After preheat or cyclic preheat, the well is used for
production, and steam injection occurs only at the points
designated hereunder, with packers and preferably with blank pipe
separating injection section(s) from production sections. The blank
pipe, with relatively short length or preferably controllable
length during operation, may help provide differential pressure and
thus minimize steam breakthrough at the production section.
Injection sections need not be large herein, and can be on the
order of <1-100 m, or 1-50 m or 20-40.
[0053] The ideal length of blank pipe will vary according to
reservoir characteristics, oil viscosity as well as injection
pressures and temperatures, but a suitable length is in the order
of 10-40 feet or 20-30 feet of blank liner. It may also be possible
to use a sliding sleeve and thus allow the benefits of a blind
interval, yet recover the oil behind the blind interval by sliding
the sleeve in one direction or the other, thus sliding the blind
interval. It may also be possible to substitute FCDs for the blind
pipe.
[0054] A suitable arrangement might thus be a 300-500 meter long
production passage, 10-40 meter blind interval, packer, <1-40
meter long injection passage followed by another packer, 10-40
meter blind interval and 300-500 meter production passage. Another
arrangement might have two injection points: 300 meter production,
10-20 blind interval, packer, 1-10 injection, packer, 10-20 blind
interval, 600 meter production, 10-20 blind interval, packer, 1-10
m injection, packer, 10-20 blind interval, 300 meter production.
Yet another arrangement might be 200 meter production, 10-20 blind
interval, packer, 1-10 injection, packer, 10-20 blind interval, 400
meter production, 10-20 blind interval, packer, 1-10 m injection,
packer, 10-20 blind interval, 400 meter production, 10-20 blind
interval, packer, 1-10 injection, packer, 10-20 blind interval, and
200 meter production.
[0055] By "heel end" herein we include the first joint in the
horizontal section of the well, or the first two joints.
[0056] By "toe end" herein we include the last joint in the
horizontal section of the well, or the last two joints.
[0057] By "middle" herein we refer to 25-75% of the horizontal well
length, but preferably from 40-60% or 45-55%.
[0058] By "between the toe end and the heel end", we mean an
injection point that lies between the first and last joint or two
of the ends of the horizontal portion of the well.
[0059] As used herein, flow control device "FCD" refers to all
variants of tools intended to passively control flow into or out of
wellbores by choking flow (e.g., creating a pressure drop). The FCD
includes both inflow control devices "ICDs" when used in producers
and outflow control devices "OCDs" when used in injectors. The
restriction can be in form of channels or nozzles/orifices or
combinations thereof, but in any case the ability of an FCD to
equalize the inflow along the well length is due to the difference
in the physical laws governing fluid flow in the reservoir and
through the FCD. By restraining, or normalizing, flow through
high-rate sections, FCDs create higher drawdown pressures and thus
higher flow rates along the bore-hole sections that are more
resistant to flow. This corrects uneven flow caused by the heel-toe
effect and heterogeneous permeability.
[0060] By "providing" a well, we mean to drill a well or use an
existing well. The term does not necessarily imply contemporaneous
drilling because an existing well can be retrofitted for use, or
used as is.
[0061] By being "fitted" for injection or production what we mean
is that the completion has everything is needs in terms of
equipment needed for injection or production.
[0062] "Vertical" drilling is the traditional type of drilling in
oil and gas drilling industry, and includes any well<45.degree.
of vertical.
[0063] "Horizontal" drilling is the same as vertical drilling until
the "kickoff point" which is located just above the target oil or
gas reservoir (pay-zone), from that point deviating the drilling
direction from the vertical to horizontal. By "horizontal" what is
included is an angle within 45.degree. (.ltoreq.45.degree.) of
horizontal. Of course every horizontal well has a vertical portion
to reach the surface, but this is conventional, understood, and
typically not discussed.
[0064] A "perforated liner" or "perforated pipe" is a pipe having a
plurality of entry-exits holes throughout for the exit of steam and
entry of hydrocarbon. The perforations may be round or long and
narrow, as in a "slotted liner," or any other shape.
[0065] A "blank pipe" or "blank liner" is a joint that lacks any
holes.
[0066] A "packer" refers to a downhole device used in almost every
completion to isolate the annulus from the production conduit,
enabling controlled production, injection or treatment. A typical
packer assembly incorporates a means of securing the packer against
the casing or liner wall, such as a slip arrangement, and a means
of creating a reliable hydraulic seal to isolate the annulus,
typically by means of an expandable elastomeric element. Packers
are classified by application, setting method and possible
retrievability.
[0067] A "joint" is a single section of pipe.
[0068] The use of the word "a" or "an" when used in conjunction
with the term "comprising" in the claims or the specification means
one or more than one, unless the context dictates otherwise.
[0069] The term "about" means the stated value plus or minus the
margin of error of measurement or plus or minus 10% if no method of
measurement is indicated.
[0070] The use of the term "or" in the claims is used to mean
"and/or" unless explicitly indicated to refer to alternatives only
or if the alternatives are mutually exclusive.
[0071] The terms "comprise", "have", "include" and "contain" (and
their variants) are open-ended linking verbs and allow the addition
of other elements when used in a claim.
[0072] The phrase "consisting of" is closed, and excludes all
additional elements.
[0073] The phrase "consisting essentially of" excludes additional
material elements, but allows the inclusions of non-material
elements that do not substantially change the nature of the
invention.
[0074] The following abbreviations are used herein:
TABLE-US-00001 bbl Oil barrel, bbls is plural CPSW-SAGD Center
point injection SW-SAGD CSOR Cumulative Steam to oil ratio CSS
Cyclic steam stimulation DW-SAGD dual well SAGD ES-SAGD Expanding
solvent-SAGD FCD Flow control device MPSW-SAGD MULTI-Point SW-SAGD
OOIP Original Oil in Place SAGD Steam assisted gravity Drainage SD
Steam drive SOR Steam to oil ratio SW-SAGD Single well SAGD
BRIEF DESCRIPTION OF THE DRAWINGS
[0075] FIG. 1A shows traditional SAGD wellpair, with an injector
well a few meters above a producer well.
[0076] FIG. 1B shows a typical steam chamber.
[0077] FIG. 2A shows a SW-SAGD well, wherein the same well
functions for both steam injection and oil production. Steam is
injected into the toe (in this case the toe is updip of the heel),
and the steam chamber grows towards the heel. Steam control is via
packer.
[0078] FIG. 2B shows another SW-SAGD well configuration wherein
steam is injected via ICCT, and a second tubing is provided for
hydrocarbon removal.
[0079] FIG. 3 center point injection SW-SAGD (CPSW-SAGD).
[0080] FIG. 4 multi-point injection SW-SAGD (MPSW-SAGD). One
injection point is situated at 1/4 well length from the heel and
the other 3/4 well length from the heel, and each steam chamber
grows in both directions, meeting in the middle of the well.
[0081] FIG. 5 shows simulated oil saturation profiles of (A)
conventional SW-SAGD, (B) SW-SAGD with center injection point (half
of full well length shown), and (C) SW-SAGD with two injection
points (quarter of full well length shown) after 3 years of steam
injection. All simulations performed with CMG-STARS using a fine
grid block.
[0082] FIG. 6 shows simulated temperature profiles of (A)
conventional SW-SAGD, (B) CPSW-SAGD with center injection point
(half of full well length shown), and (C) MPSW-SAGD with two
injection points (quarter of full well length shown) after 3 years
of steam injection.
[0083] FIG. 7 shows a comparison of oil production rate. Note that
the End-Injector case is conventional SW-SAGD, the Center-Injector
case is CWSW-SAGD with a center injection point, and the
Two-Injector case is MPSW-SAGD with two injection points spaced for
equally sized steam chambers.
[0084] FIG. 8 is a comparison of oil recovery using the same three
well configurations as in FIG. 7.
DESCRIPTION OF EMBODIMENTS
[0085] The present disclosure provides a novel well configurations
and method for SW-SAGD.
[0086] This novel modification to the conventional single-well SAGD
(SW-SAGD) process varies the location and number of steam injection
points during the production phase, and the same points can be used
in preheat or cyclic preheat.
[0087] The conventional SW-SAGD process grows a steam chamber and
drains oil by gravity by utilizing one single horizontal well with
steam injected only at the toe and liquid produced through the rest
of the well. SW-SAGD has potential to unlock vast thin-zone (5-20 m
pay) oil sand resources where SAGD using well pairs is economically
and technically challenging.
[0088] However, the conventional SW-SAGD normally suffers from slow
steam chamber growth and low oil production rate as the steam
chamber can only grow from toe gradually towards the heel. This
appears to be very ineffective, and seriously limits the usefulness
of SW-SAGD.
[0089] In this invention, we propose an improved SW-SAGD process
with one or more steam injection points between the toe and heel
end. For example, a center steam injection point can be used, or
multiple steam injection points spaced for equal steam chamber
development can be used to significantly accelerate steam chamber
growth and oil recovery. The superior recovery performance of the
proposed configuration and methods is confirmed by our simulation
results.
[0090] It is surprising that this elegant solution to the low
production level issue with SW-SAGD has never been proposed before.
However, one reason is that most SAGD simulations are either run as
2D cross-sections, or as 3D models with relatively large gridding
in the wellbore direction (typically 25-100 m), both of which will
either eliminate the "end effect" (in the case of 2D simulations),
or seriously under-estimate it (in the case of large-block 3D
simulations). Thus, given the tools typically available to the
petroleum engineer, even if the idea was attempted, traditional
models would not show any benefit.
Conventional SW-SAGD
[0091] The conventional SW-SAGD utilizes one single horizontal well
to inject steam into reservoir through toe and produce liquid (oil
and water) through mid and heel of the well, as schematically shown
in FIGS. 2A and B. A steam chamber is expected to form and grow
from the toe of the well. Similar to the SAGD process, the oil
outside of the steam chamber is heated up with the latent heat of
steam, becomes mobile, and drains with steam condensate under
gravity towards the production portion of the well. With continuous
steam injection through toe and liquid production through the rest
of the well, the steam chamber expands gradually towards to the
heel to extract oil.
[0092] Due to the unique arrangement of injection and production,
the SW-SAGD can also benefit from pressure drive in addition to
gravity drainage as the recovery mechanisms. Also, compared with
its counterpart, the traditional dual well or "DW-SAGD"
configuration, SW-SAGD requires only one well, thereby saving
almost half of well cost. SW-SAGD becomes particularly attractive
for thin-zone applications where placing two horizontal wells with
the typical 4-10 m vertical separation required in the SAGD is
technically and economically challenging.
[0093] SW-SAGD, however, exhibits several disadvantages leading to
slow steam chamber growth and low oil rate. First of all, SW-SAGD
is not efficient in developing the steam chamber. The steam chamber
growth depends largely upon the thermal conduction to transfer
steam latent heat into cold reservoir and oil drainage under
gravity along the chamber interface. Due to the arrangement of
injection and production points in the conventional SW-SAGD, the
steam chamber can grow only direction towards the heel. In other
words, only one half of the surface area surrounding the steam
chamber is available for heating and draining oil. Secondly, a
large portion of the horizontal well length perforated for
production does not actually contribute to oil production until the
steam chamber expands over the whole length. This is particularly
true during the early stage where only a small portion of the well
close to the toe collects oil.
CPSW-SAGD
[0094] To overcome the aforementioned issues associated with the
conventional SW-SAGD, we propose steam injection in between the
heel and toe to improve the recovery performance at about the
center of the well. By "center" herein, we refer to roughly the
center of the longitudinal portion of the well, and do not consider
the vertical portion. By doing this, the steam chamber can grow in
both directions from roughly the middle. The essential idea is to
allow full development of steam chamber from both sides and
increase the effective production well length earlier in the
process.
[0095] FIG. 3 shows schematically a simple, but effective (as
demonstrated later by simulation) process modified from the
conventional SW-SAGD, in which the steam injection point is placed
in the middle of the horizontal well. The toe and heel sections of
the horizontal well, isolated from the steam injection portion by
thermal packers (indicated by the boxes with the X therein) within
the wellbore, are perforated and serve as producer to collect
heated oil and condensed water.
[0096] As illustrated in FIG. 3, the steam chamber can now grow
from both sides, with the effective thermal and drainage interfaces
virtually doubled. Consequently, the effective production well
length is doubled, resulting in a significant uplift in oil
production rate.
MPSW-SAGD
[0097] To further improve the performance SW-SAGD, multiple steam
injection points can be introduced into the wellbore to initiate
and grow a serial of steam chambers simultaneously. FIG. 4 gives an
example with two injection points, one at 1/4 well length from the
heel and the other 3/4 well length from the heel. The SW-SAGD with
multiple steam injection points can significantly accelerate the
oil recovery by engaging more well length into effective
production. With two injection points as placed in FIG. 4, the dual
steam chambers will each grow in both directions, and meet in
roughly the middle of the well.
[0098] The number of the steam injection points and intervals
between them normally need to be determined and optimized based on
the reservoir properties and economics. It is worth pointing out
that implementing multiple steam injection points within a single
wellbore adds complexity to the wellbore design and consequently
well cost, necessitating the providing of multiple injections
points and additional packers. Nevertheless, the proposed invention
presents a considerable potential for improving SW-SAGD
applications to thin-zone bitumen reservoirs.
Steam Chamber Simulations
[0099] To evaluate the performance of the proposed modification to
the conventional SW-SAGD, numerical simulation with a 3D
homogeneous model was conducted using Computer Modeling Group.RTM.
Thermal & Advanced Processes Reservoir Simulator, abbreviated
CMG-STARS. CMG-STARS is the industry standard in thermal and
advanced processes reservoir simulation. It is a thermal, k-value
(KV) compositional, chemical reaction and geomechanics reservoir
simulator ideally suited for advanced modeling of recovery
processes involving the injection of steam, solvents, air and
chemicals.
[0100] The reservoir simulation model was provided the average
reservoir properties of Athabasca oil sand, with an 800 m long
horizontal well placed at the bottom of a 20 m pay. The simulation
considered three cases, the conventional SW-SAGD, CPSW-SAGD with
centered injector, and MPSW-SAGD with two injectors (one 200 m and
the other 600 m from heel). A smaller than usual grid size was
modeled in order to capture the effects (e.g., 1-5 m, preferably 2
m). No startup period was modeled. The modeled operational
conditions, including pressure and injection rates, were similar to
a typical SAGD operation.
[0101] FIGS. 5 and 6 show the simulated profiles of oil saturation
and temperature after 3-year steam injection for the three cases.
Note that due to element of symmetry, the case of the SW-SAGD with
centered injection point only shows one half of the well length and
the case of the SW-SAGD with two injection points shows a quarter
of the well length.
[0102] For the conventional SW-SAGD, the steam chamber extends to
about 1/3 of the well length, leaving 2/3 of the well length not in
production. The case with centered steam injection point results in
steam chamber development over half of the well length and the case
with two injection points show the steam zone over almost 80% of
the well length. Thus, simply moving the steam injection point to
the middle of the well, and by adding more than one injection
point, the steam zone can cover the entire well.
Production Simulations
[0103] In order to prove the benefit of the CPSW-SAGD and MPSW-SAGD
we performed production simulations, also using CMG-STARS. FIG. 7
compares the oil production rate of the three cases from above.
[0104] Surprisingly, the oil production rate is almost doubled from
the conventional SW-SAGD by placing the injection point in the
middle of the well, and is further lifted by 50% when two injection
points are implemented.
[0105] The oil rate drop at 1600 days in the case with two
injection points is due to the steam chamber coalescence. With two
injection points, two steam chambers develop that are separated
from each other at the beginning. As steam injection continues,
both steam chambers will grow vertically and laterally. Depending
on the distance between the two steam injection points, the edges
of the two steam chambers will eventually meet somewhere in the
mid-point, in a phenomena called "coalescence" of the steam
chamber. The sum of surface area of the two chambers is larger
before coalescence than after coalescence, because one of the
boundaries is shared after coalescence. The heating of oil and
resulting oil drainage depends on the surface or contact area.
Therefore, it is typical that the oil rate drops when the steam
chamber coalescences.
[0106] FIG. 5 shows the comparison of the oil recovery factor,
which again illustrates the significant improvement of the
described invention over the conventional SW-SAGD.
[0107] We have not yet run a simulation case with 3 injection
points, but we expect even faster oil recovery. It is predicted
that the wells can thereby be longer to fully realize the benefits
of three injection points.
[0108] The simulated payzone was big at 20 m. However, the relative
gain really comes from the surface area increase due to doubling
size of the incipient steam chambers. Thus, even with a thinner pay
zone, we still expect the same relative performance
improvement.
[0109] The following references are incorporated by reference in
their entirety for all purposes.
[0110] Falk, K., et al., Concentric CT for Single-Well Steam
Assisted Gravity Drainage, World Oil, July 1996, pp. 85-95.
[0111] McCormack, M., et al., Review of Single-Well SAGD Field
Operating Experience, Canadian Petroleum Society Publication, No.
97-191, 1997.
[0112] Moreira R. D. R., et al., IMPROVING SW-SAGD (SINGLE WELL
STEAM ASSISTED GRAVITY DRAINAGE), Proceedings of COBEM 2007 19th
International Congress of Mechanical Engineering, available online
at
www.abcm.org.br/pt/wp-content/anais/cobem/2007/pdf/COBEM2007-0646.pdf.
[0113] Faculdade de Engenharia Mecanica, Universidade estadual de
Campinas. Sa
[0114] SPE-59333 (2000) Ashok K. et al., A Mechanistic Study of
Single Well Steam Assisted Gravity Drainage.
[0115] SPE-54618 (1999) Elliot, K., Simulation of early-time
response of singlewell steam assisted gravity drainage
(SW-SAGD).
[0116] SPE-153706 (2012) Stalder, Test of SAGD Flow Distribution
Control Liner System, Surmont Field, Alberta, Canada
[0117] US20120043081 Single well steam assisted gravity
drainage
[0118] US20130213652 SAGD Steam Trap Control
[0119] US20140000888 Uplifted single well steam assisted gravity
drainage system and process
[0120] U.S. Pat. No. 5,626,193 Method for recovering heavy oil from
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* * * * *
References