U.S. patent application number 14/521356 was filed with the patent office on 2015-04-23 for single horizontal well thermal recovery process.
The applicant listed for this patent is Cenovus Energy Inc.. Invention is credited to Harbir S. CHHINA, Arun SOOD, Alvin WINESTOCK.
Application Number | 20150107842 14/521356 |
Document ID | / |
Family ID | 52825160 |
Filed Date | 2015-04-23 |
United States Patent
Application |
20150107842 |
Kind Code |
A1 |
SOOD; Arun ; et al. |
April 23, 2015 |
SINGLE HORIZONTAL WELL THERMAL RECOVERY PROCESS
Abstract
The present disclosure describes a method for the recovery of
hydrocarbons using a single horizontal well having both injection
and production means. The well has a means for increasing fluid
flow resistance in the wellbore. The injection and production means
are operated so as to increase the fluid flow into the reservoir
and reduce the fluid flow in the well. The means to increase fluid
flow includes a constriction in the wellbore between the injection
and production means, flow conditioners placed along a portion of
the well between the injection and production means, and sealing
elements placed in the well between the injection and production
means. The production and injection openings are also positioned
relative to the flow conditioners and sealing elements.
Inventors: |
SOOD; Arun; (Calgary,
CA) ; WINESTOCK; Alvin; (Calgary, CA) ;
CHHINA; Harbir S.; (Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Cenovus Energy Inc. |
Calgary |
|
CA |
|
|
Family ID: |
52825160 |
Appl. No.: |
14/521356 |
Filed: |
October 22, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61894809 |
Oct 23, 2013 |
|
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|
Current U.S.
Class: |
166/306 |
Current CPC
Class: |
E21B 43/2406
20130101 |
Class at
Publication: |
166/306 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 33/128 20060101 E21B033/128; E21B 43/12 20060101
E21B043/12; E21B 17/00 20060101 E21B017/00 |
Claims
1. A method of producing viscous hydrocarbons from a subterranean
formation, comprising: providing a single horizontal well within
the subterranean formation wherein the horizontal well comprises an
outer wall, at least one injector for injecting a mobilizing fluid
into the reservoir, the at least one injector comprising a conduit
within the well to inject the mobilizing fluid to the distal end of
the conduit, an annulus extending along the longitudinal axis of
the well, and at least one producing component, positioned apart
from the at least one injector, for producing hydrocarbons from the
reservoir; providing, within the annulus, a flow conditioner for
substantially increasing axial fluid flow resistance within the
annulus along a length of the horizontal well between the at least
one injector and the at least one producing component; injecting
the mobilizing fluid through the at least one injector; operating
the at least one injector and the at least one producing component
to control the ratio of the flow resistance in the well to the flow
resistance in the formation, thereby reducing the amount of the
injected mobilizing fluid moving through the annulus from the at
least one injector to the at least one producing component and
increasing the amount of the injected mobilizing fluid entering and
moving through the formation before being displaced into the well
to the at least one producing component; and producing viscous
hydrocarbons through the at least one producing component.
2. The method of claim 1 wherein the method uses: a
gravity-dominated fluid flow or displacement mechanism to recover
the viscous hydrocarbons; a convectively dominated fluid flow or
displacement mechanism to recover the viscous hydrocarbons; or a
combination of convective and gravity fluid flow and displacement
mechanisms to recover the viscous hydrocarbons.
3. The method of claim 1 wherein the flow conditioner for
increasing fluid flow resistance provides a constriction in the
annulus to increase the fluid flow resistance of the injected
mobilizing fluid as the fluid re-enters the annulus from the
reservoir.
4. The method of claim 1 wherein the flow conditioner for
increasing fluid flow resistance is selected from the group
consisting of: one or more flow constrictors positioned in the
annulus; one or more partial sealing elements positioned in the
annulus; and two or more sealing elements positioned in the annulus
of the well between the at least one injector and the at least one
producing component.
5. The method of claim 4 wherein the one or more flow constrictors
extend along a portion of the length of the annulus between the
injector and the producing component.
6. The method of claim 4 wherein the two or more sealing elements
are operated in series or simultaneously.
7. The method of claim 4 further comprising operating the two or
more sealing elements in a staged manner by activating sealing
elements in a staged manner in a direction from the at least one
injector to the at least one producing component.
8. The method of claim 4 wherein, following an initial activation
of the two or more sealing elements, the sealing elements are
deactivated, moved longitudinally through the annulus and
reactivated in a new position relative to the at least one injector
portion and the at least one producing component.
9. The method of claim 4 wherein prior to one of the sealing
elements being activated, the viscous hydrocarbons in the formation
immediately downstream of the one of the sealing elements are
sufficiently mobile to undergo displacement by the injected
mobilizing fluid once the one of the sealing elements has been
activated.
10. The method of claim 4 wherein, in the interval(s) between the
two or more sealing elements, the outer wall of the well, contains
openings, or groups of openings, to allow hydraulic communication
between the well and the formation.
11. The method of claim 4 wherein the portion of the outer wall of
the well between the two or more sealing elements does not have
openings into the reservoir.
12. The method of claim 4, wherein the one or more partial sealing
elements comprises a sealing element with one or more flow conduits
extending through the sealing element for allowing a desired flow
of the mobilizing fluid.
13. The method of claim 12 wherein the one or more partial sealing
elements comprises more than one sealing element with one or more
flow conduits extending through each of the more than one sealing
element, wherein the flow conduits in each sealing element allow
for a different mobilizing fluid flow rate than the fluid flow rate
in at least one other of the sealing elements.
14. The method of claim 12 where the flow velocity in one or more
of the flow conduits is sonic flow and critical flow.
15. The method of claim 1 wherein the step of producing the viscous
hydrocarbons comprises pumping the hydrocarbons to the surface
without maintaining a substantial liquid level in the horizontal
well.
16. The method of claim 1 wherein the viscous hydrocarbons are
selected from the group consisting of bitumen, heavy oil, and
unmobilized hydrocarbons.
17. The method of claim 1 wherein the injected fluid comprises
steam, hot water, light hydrocarbons, or mixtures thereof or one or
more of non-condensing gases and surfactants.
18. The method of claim 1 wherein: the injector injects fluids at
or near a toe of the horizontal well and the producing component
produces viscous hydrocarbons at or near a heel of the horizontal
well; or the injector injects fluids at or near a heel of the well
and the producing component produces the viscous hydrocarbons at or
near a toe of the well.
19. The method of claim 1 wherein the at least one injector
includes two injector, each injector injecting the mobilizing fluid
at a different section in the well and each of the two injector
having flow conditioners for substantially increasing axial fluid
flow resistance within the annulus along the length of the
horizontal well.
20. The method of claim 1 wherein a plurality of single horizontal
wells is employed.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of priority of U.S.
Provisional Patent Application No. 61/894,809, entitled "SINGLE
HORIZONTAL WELL THERMAL RECOVERY PROCESS" filed Oct. 23, 2013,
which is hereby incorporated by reference in its entirety.
FIELD
[0002] The present disclosure relates generally to oil recovery
processes and particularly to thermal recovery and thermal/solvent
recovery processes that may be applied in viscous hydrocarbon
reservoirs, and specifically in oil sands reservoirs. More
specifically, the disclosure describes the use of a single
horizontal well for injection and production in thermal and/or
solvent recovery processes.
BACKGROUND
[0003] Among the deeper, non-minable deposits of hydrocarbons
throughout the world are extensive accumulations of viscous
hydrocarbons. In some instances, the viscosity of these
hydrocarbons, while elevated, is still sufficiently low to permit
their flow or displacement without the need for extraordinary
means, such as the introduction of heat or solvents. In other
instances, such as in Canada's bitumen-containing oil sands, the
hydrocarbon accumulations are so viscous as to be practically
immobile at native reservoir conditions. As a result, external
means, such as the introduction of heat or solvents, or both, are
required to mobilize the resident bitumen and subsequently harvest
it.
[0004] A number of different techniques have been used to recover
these hydrocarbons. These techniques include steam flood, (i.e.,
displacement), cyclic steam stimulation, steam assisted gravity
drainage, and in situ combustion, to name a few. These techniques
use different key mechanisms to produce hydrocarbons.
[0005] Commercially, the most successful recovery technique to date
in Canada's oil sands is Steam Assisted Gravity Drainage (SAGD),
which creates and then takes advantage of a highly efficient fluid
density segregation, or gravity drainage, mechanism in the
reservoir to produce oil. A traditional system which is a
concomitant of the SAGD process is the SAGD well pair. It typically
consists of two generally parallel horizontal wells, with the
injector vertically offset from and above the producer.
[0006] SAGD was described by Roger Butler in his patent CA
1,130,201 issued Aug. 24, 1982 and assigned to Esso Resources
Canada Limited. Since that time, numerous other patents pertaining
to aspects and variations of SAGD have been issued. Also, many
technical papers have been published on this topic.
[0007] The SAGD process, as embodied in the operation of a well
pair, and as applied in an oil sand, typically involves first
establishing communication between the upper and lower horizontal
wells. There are both thermal and non-thermal techniques for
establishing this inter-well communication. Subsequently, steam is
injected into the overlying horizontal well on an ongoing basis.
Due to density difference, the steam tends to rise and heat the oil
sand, and thereby mobilizes the resident bitumen. The mobilized
bitumen is denser than the steam, and tends to move downward
towards the underlying horizontal well from which it is produced.
By operating the injector and the producer under appropriately
governed conditions, it is possible to use the density difference
to counteract the tendency of more mobile fluids to channel or
finger through the less mobile fluids and overwhelm the producing
well. Thus, in traditional SAGD operations, each well in the well
pair has a specific and distinctive role in ensuring that the
efficiencies which can be achieved with a gravity-dominated process
are realized.
[0008] Not long after the patenting of SAGD, various investigators
began to examine the feasibility of operating a process which, like
SAGD, is gravity-dominated, but which is operable with a single
well rather than a well pair. The early concepts involved a single
vertical well and represent a different configuration than that
described in the present disclosure.
[0009] In U.S. Pat. No. 5,014,787 filed Aug. 16, 1989, Duerksen of
Chevron describes a single vertical well system, with detailed
focus on the tubing-casing-packer configuration within the
wellbore. Packers are installed to confine and direct flow within
the wellbore and to segregate within the wellbore the injection and
production intervals. This system utilizes a "drive fluid".
Generally drive fluids are used in non-SAGD systems to drive or
"push" the hydrocarbons to a producer well. This is in contrast to
recovery processes in which a gravity drainage mechanism is either
dominant or operative. Duerksen's system and associated method
utilize a "drive fluid" to establish near-wellbore communication
within the reservoir between an upper set of injection perforations
and a lower set of production perforations and does not mention
gravity drainage or a gravity-dominated process.
[0010] In U.S. Pat. No. 5,024,275 filed Dec. 8, 1989, to Anderson
et al, assignee Chevron, a similar system is described as that in
U.S. Pat. No. 5,014,787 to Duerksen, but with somewhat modified
vertical wellbore hydraulics. Also, mention is made of maintaining
a liquid level within the reservoir such that uncondensed fluids
are not inadvertently produced. However, as with U.S. Pat. No.
5,014,787, reference is made to a "drive fluid". There is no
mention of a recovery process which includes gravity drainage as an
operative mechanism.
[0011] U.S. Pat. No. 5,238,066 filed Mar. 24, 1992 to Beattie et
al., assignee Exxon, pertains to a method introduced in the later
stages of cyclic steam stimulation (CSS) operation, and involves
alternating periods of steam injection into upper perforations in a
vertical well followed by hydrocarbon production from lower
perforations. There is no mention or implication of a
gravity-dominated recovery process or a process in which gravity
drainage plays a role.
[0012] The paper titled "Lloydminster, Saskatchewan Vertical Well
SAGD Field Test Results", published in the Journal of Canadian
Petroleum Technology, November 2010, Volume 49, No. 11, by Miller
& Xiao of Husky Energy, describes a field experiment involving
a single vertical well SAGD-type operation. The reservoir in which
the experiment was conducted involved viscous oil, but with
considerably lower native viscosity (i.e., higher mobility) than
the types of bitumen present in the oil sands. The authors
indicated that the test "demonstrated that a single vertical well
SAGD configuration could be successfully completed and operated".
For reasons that the authors attributed to geology and initial
fluid distribution within the reservoir setting, the authors noted
that "Field performance of single vertical SAGD Well 4C11-1 was not
as good as expected", and suggested that single vertical well SAGD
methodology could be "used to help determine if sufficient vertical
permeability exists for the low-pressure gravity-based horizontal
well SAGD process to be successful". That is, the authors proposed
that their single vertical well SAGD methodology could be applied
as a diagnostic technique for determining vertical permeability
within the reservoir rather than as an effective recovery
process.
[0013] Other vertical well configurations have been proposed. For
example, X-Drain.TM., a trademarked and patented concept by
GeoSierra/Halliburton involves a single vertical well that employs
a SAGD-type process. Emanating from the vertical well are a number
of highly permeable vertical planes, similar to vertical hydraulic
fractures, with the fractures propped or held open by a permeable
propping agent. Each such plane has its own azimuth so that the
effect, when viewed from above, is geometrically similar to a hub
(the vertical well) and spokes (the induced multi-azimuth vertical
planes). Steam is injected into the upper portion of the well and
moves outward through the highly permeable propping agent contained
within these multi-azimuth vertical planes to mobilize the bitumen
at the faces of each plane.
[0014] For many decades, Imperial Oil has practiced a cyclic steam
stimulation process at their Cold Lake oil sands operation using
vertical and inclined wells. The viability of the recovery process
depends on the use of formation fracturing during the injection
cycle to create a largely vertical fracture that spans a
significant vertical portion of the formation. While this is a
single-well process, the perforations or wellbore openings for
injection are the same as those used for production. Thus, the
recovery mechanism relies on a production flow path that is
fundamentally the same as, and indeed largely created by, the
preceding injection flow path.
[0015] Canadian patent application CA 2,723,198 filed Nov. 30, 2010
to Shuxing, assignee ConocoPhillips, describes a vertical well
recovery process which can include a gravity-dominated mechanism.
The patent application describes a well configuration involving a
single well with an upper and a lower set of openings or
perforations. It further requires the creation of two horizontal
fractures--one opposite the upper injection interval and one
opposite the lower producing interval. However, there are
additional costs and other disadvantages to fracturing so it may
not be feasible or desirable for a particular formation.
[0016] Because of their vertical well orientation, none of the
foregoing single-well techniques enjoys the inherent advantage
offered by horizontally oriented wells, which can traverse and
access a large portion of reservoir. The obvious advantage of a
horizontally oriented single well was recognized by various
investigators, and concepts for a single horizontal well recovery
system and process were put forward.
[0017] One such approach is described in U.S. Pat. No. 5,167,280 to
Sanchez et al, assignee Mobil, issued Dec. 1, 1992. This patent
discusses the circulation within the wellbore of a solvent which is
capable of rendering the viscous oil more mobile. A process is
employed in which the pressure gradient and the fluid concentration
gradient are opposed. That is, the pressure gradient is maintained
so that flow is inward from the reservoir to the well. At the same
time, the viscous oil reservoir is exposed to the solvent via
diffusion. The aim is to obtain simultaneous outward stimulation of
the reservoir by the solvent and inward flow of mobilized viscous
oil to the well. The practicality of maintaining the operating
conditions necessary to achieve opposing gradients is highly
questionable, as an inordinate degree of monitoring and control
would be required.
[0018] Canadian Patent 2,162,741 to Nzekwu et al, assignee CNRL,
and filed Dec. 20, 2005, describes a single horizontal well
recovery process that includes both gravity drainage and steam
flooding. The patent describes a process whereby steam is directed
to the distal end of the single horizontal well via insulated
tubing, making its return toward the proximal end of the well in
the annular region between tubing and liner such that a portion of
the returning steam migrates through the slotted liner into the
reservoir and mobilizes oil. A problem with this type of
configuration is that the resistance to fluid flow along the path
from the well into the reservoir is very much greater than the
fluid resistance along the annulus between the outer surface of the
tubing and the inner surface of the liner. Accordingly, only a
small portion of the overall injected fluids will enter the
reservoir and mobilize oil. In a low pressure operation mode,
Nzekwu restricts the injection and production rates to such an
extent that a liquid level builds in the vertical part of the
primarily horizontal well, which hydrostatically supports the steam
chamber pressure. That is, the liquid head is equal to the steam
chamber pressure. There is a low pressure drop in the annulus from
the distal end to the proximal end. Using this system, the
longitudinal growth of the steam chamber in the reservoir, i.e.
from the toe towards the heel, is promoted by the small pressure
drop that exists along the horizontal well and would be extremely
slow and result in very low production rates. In a high pressure
mode, Nzekwu describes a preferred configuration in which a packer
is placed near the distal end of the well to isolate the injection
and production zones in an attempt to direct more of the steam into
the reservoir. As described by Nzekwu, the packer is set over a
blanked-off interval of the liner that is approximately one metre
in length. Thus the interval of isolation is extremely small
relative to the length of a typical horizontal well, and the
ability of that isolation interval to cause a diversion of injected
fluids into the reservoir before they ultimately flow back into the
wellbore will be very limited in space and time. That is, as some
of the reservoir on the downstream side of the packer is heated,
and the hydrocarbons mobilized and produced, the injected steam
will enter the reservoir on the upstream side of the packer and
exit the reservoir shortly thereafter on the downstream side of the
packer, where it will re-enter the wellbore and flow to the
proximal end with little or no further effect in mobilizing
oil.
[0019] A paper by Elliot and Kovscek prepared for the U.S.
Department of Energy, dated June 2001, and titled "A Numerical
Analysis of Single-Well Steam Assisted Gravity Drainage (SW-SAGD)
Process" describes simulations carried out in which the horizontal
well is subdivided into two equal lengths, with the injection
interval occupying the distal half and the production interval
occupying the proximal half of the wellbore length. The distal and
proximal segments can be demarcated within the wellbore by a single
intervening packer, or packer assembly, and open intervals for
injection and production are separated from each other by a
distance of 30 metres. Relative to the 800 metre length of the well
represented in their simulations, which is a typical length for a
SAGD well, this is a very small separation interval, so that fluids
injected into the reservoir on the upstream side of the packer will
short-circuit back into the wellbore after a relatively short
traverse within the reservoir. However, the authors comment that
while their work involved maintaining this equal-length
configuration, it is not necessary to do so. The authors also limit
the effectiveness of their method by noting that "application of
SWSAGD to exceptionally viscous oils will be difficult". The
authors suggest an upper limit of 10 Pa-s. This is in contrast to
the invention to be described herein, which includes devices, well
configurations and techniques that promote or maximize exposure of
the reservoir to mobilizing fluids. A further contrast between the
present invention and that of Elliot and Kovscek is the
applicability of the present invention in oil sands where the
native bitumen may be 100 times more viscous than the limit set by
Elliot and Kovscek on the applicability of their method.
[0020] A paper by Marin et al of PDVSA, presented at the World
Heavy Oil Congress in Edmonton Alberta in 2008 (Paper 2008-348),
and titled "SW-SAGD Pilot Project in the Well MFB-617, TL Sands,
MFB-15 Reservoir, Bare Field, Eastern Basin of Venezuela" discloses
a single horizontal well configuration for SAGD operation. The
wellbore contains two strings--one for injection and the other for
production. However, while the injection string traverses the
length of the horizontal wellbore, the production string is
confined to the vertical portion of the wellbore. FIG. 4 of the
paper clearly illustrates the verticality of the production tubing
and this is re-enforced within the text which describes the tubing
as having been set 650 ft. above the top of the reservoir.
[0021] This same well (MFB-617) is the subject of a paper by Mago
et al of PDVSA, presented at the World Heavy Oil Congress in
Aberdeen Scotland in 2012 (Paper 2012-348). There are no indicated
completion changes for the well, so that the basic configuration
teaches away from that taught in the present disclosure. However,
the authors conducted simulation studies involving alternative
configurations for steam injection. In those simulations, steam is
injected along a horizontal well that involve configurations with
one, two and three steam injection points along the length of the
well. However, there are no teachings in this paper that pertain to
management of the resistances to flow as is the case with the
present disclosure.
[0022] Canadian Patent 2,752,059 to Kjorholt, assignee Statoil,
describes a single horizontal well whose wellbore contains a
production conduit and an injection conduit, with openings in each
conduit that are distributed along the horizontal length of the
wellbore. The openings in the production conduit may be staggered
laterally with respect to the openings in the injection conduit. No
packers or other flow restraints, or flow conditioners, as will be
described in the case of the present invention, are employed to
determine, or assist in the determination of, the flow distribution
along the wellbore.
[0023] A single horizontal well recovery process is disclosed by
Laricina in their update of Oct. 31, 2012 to the Alberta Energy
Resources Conservation Board, and titled "Saleski Phase 1 Project
Update". Laricina describe their proposed single well recovery
process as follows: "The recovery process that has been selected is
single well cyclic SAGD process with the use of solvent technology.
This process varies the rates and compositions of solvent and steam
injected over the life of the wells. The process alternates between
injecting steam/solvent and producing water and mobile oil from the
well bore. The injection cycle consists of injecting steam/solvent
above reservoir pressure at 1,600 kPa to 5,100 kPa to heat the
reservoir and reduce the viscosity of the bitumen. The reservoir is
then allowed to absorb the heat from the injected steam/solvent,
condense and subcool before a production cycle starts. The
production cycle is continued until bitumen rate reaches a minimum
threshold." As described in their update, Laricina's recovery
process involves variations in procedure that incorporate Cyclic
Steam Stimulation as well as SAGD, but does not include any
management of flow along the length of a horizontal well.
[0024] The foregoing single horizontal well inventions fall into
five approaches to single horizontal well SAGD. The patent to
Sanchez et al constitutes one approach wherein opposing gradients
are operative. This approach differs profoundly from the teachings
of the present invention.
[0025] The second approach, including Nzekwu and Elliot, relies on
a fixed-position wellbore impediment, such as a packer, to divert
flow from the injection perforations outward into the reservoir so
that heating and chamber formation can occur. However, once heating
and mobilization of oil occurs within the reservoir in the vicinity
of the packer, the opportunity for steam to flow around the packer
and back into the wellbore is provided, instead of continuing to
enter the reservoir beneficially. Specifically, because of the very
high virgin viscosity of bitumen, the initial path of least
resistance for the injected mobilizing fluids in a single
horizontal well configuration will involve relatively shallow
penetration by the mobilizing fluids into the reservoir, and a
tendency thereafter to move longitudinally along the outside of the
liner and thence into the production means located along that same
wellbore, whereupon it will enter the wellbore, and will be
minimally effective or ineffective from that point onward in
mobilizing bitumen within the reservoir.
[0026] The third approach, described in the paper by Marin et al.,
involves a production string that is exclusively vertical and, as
such, teaches away from the method and system of the present
disclosure. The follow-up paper by Mago et al discusses this same
well, and includes simulations of proposed steam injection
configurations and methods. However, these configurations and
methods are fundamentally different from those of the present
disclosure.
[0027] The fourth approach, disclosed by Kjorholt, involves
horizontal injection and production strings that traverse the
wellbore, with openings at discrete intervals along each that
distribute injection and production respectively. However, the
invention does not otherwise take steps, or employs devices, which
will alter the flow and displacement patterns beneficially as does
the present disclosure.
[0028] The fifth approach, disclosed by Laricina, includes the
combination of Cyclic Steam Stimulation (CSS) and SAGD, but offers
no description of well completion configuration, nor does it
specify any associated methods to manage flow into the reservoir
and along the wellbore as does the present disclosure.
[0029] Having regard to these limitations in the prior art, it is
an object of the present disclosure to provide a single horizontal
well recovery process whose efficiency is enhanced by incorporating
methods and systems to mitigate the steam short-circuiting
tendencies associated with this type of operation and,
correspondingly, will extend the region within the reservoir over
which the viscous hydrocarbons are contacted by mobilizing fluids.
The recovery process will utilize gravity drainage and for
convective flow mechanisms to varying degrees, depending upon the
stage of the process, the well configuration and the reservoir
properties.
[0030] In addition to the foregoing five approaches to single
horizontal well processes that encompass both injection and
production functions, prior systems also include horizontal wells
with injection only.
[0031] U.S. Pat. No. 8,196,661 to Trent et al, assignee Noetic
Technologies Inc., and titled "Method for Providing a Preferential
Specific Injection Distribution from a Horizontal Injection Well",
describes a concept that involves an injection well only. As such,
the tubing that is within the casing has openings along its entire
length so that injected fluids, such as steam, may be injected
radially outward through the tubing, and thence radially outward
through the casing or liner, thereby entering the reservoir with
substantially radial flow geometry. U.S. Pat. No. 8,196,661, in
describing means to control the distribution of fluids injected
radially along the length of the wellbore, makes reference to
devices which provide means of increasing friction within the
wellbore so as to govern the flow.
[0032] CA 2,769,044 to Butland et al, assignee Alberta Flux
Solutions Ltd., and titled "Fluid Injection Device", describes a
device or system for distributing fluids, including steam, along an
injection-only wellbore with radially outward flow into the
formation. Also, it references devices or approaches which modify
the flow resistance within the wellbore to assist in the
distribution of injected fluids.
[0033] These systems with injection only from the horizontal
wellbore are concerned with a flow geometry of only the injected
fluids into the reservoir without any concern for production from
the same horizontal wellbore. This requires a different flow
geometry and the flow of different fluids than those required in a
horizontal well with both production and injection
capabilities.
[0034] There is therefore a need for increasing the flow resistance
of injected fluids in a horizontal well having both injection and
production capabilities, for the increased flow of injected fluids
into the reservoir and improved production of mobilized
hydrocarbons from the horizontal well.
SUMMARY
[0035] The present disclosure is a method and system for a recovery
process for recovering hydrocarbons from a reservoir using a single
horizontal well for both injection and production. The recovery
process may utilize gravity drainage or convective flow, or both.
The recovery process is preferably a thermal or solvent recovery
process. The system and process has an injection tubing string
which has openings only at or towards one end of the horizontal
well, preferably its toe end, to permit egress of injected fluids,
and openings or perforations along the liner or outer casing of the
wellbore to permit injection into the reservoir of mobilizing
fluids over a selected interval of the wellbore. Positioned
downstream therefrom along the casing or liner of that same
wellbore, are openings to permit production from the reservoir of
mobile and mobilized fluids.
[0036] The present disclosure minimizes or markedly reduces the
shortcutting or short-circuiting tendency of the injected fluid as
it moves outward into the reservoir along one interval of the
wellbore and returns further downstream into appropriate production
tubulars within that same horizontal wellbore. That is, the present
system and method utilizes procedures or equipment configurations,
or combinations thereof, to govern the resistance to fluid flow of
the injected fluids from the well outward into the reservoir
relative to the resistance to fluid flow of the injected fluids
along the various tubular conduits within the wellbore. This
approach results in an efficient recovery process for viscous
hydrocarbons, such as bitumen, while using only a single horizontal
well to accomplish both the injection and production functions.
[0037] When implemented, the present invention allows mobilizing
fluid to exit the wellbore and enter the reservoir, and thence
traverse a significant portion of the reservoir where it mobilizes
viscous hydrocarbons. The resulting mobile stream then re-enters a
portion of the wellbore downstream and moves to a production means,
such as a pump. To achieve this flow configuration, which permits
injection and production operations along the same wellbore, flow
gradients into and out of the reservoir must be governed while
maintaining a sufficiently long open interval that will serve as an
effective production means.
[0038] In one aspect, the present disclosure provides a method of
producing viscous hydrocarbons from subterranean bituminous
formations, such as oil sands formations, using a single horizontal
well process. The method includes providing a single horizontal
well within the subterranean formation wherein the horizontal well
has at least one injection means and at least one production means,
spaced axially along the well and apart from the at least one
injection means. Preferably the at least one injection means are
positioned at or near the toe of the well and the at least one
injection means are positioned at or near the heel of the well. The
well may also have a casing or liner which includes openings to the
formation to allow injected fluids to flow into the formation and
mobilized hydrocarbons, as well as other fluids, to flow into the
well for production. The method also includes providing a means for
substantially increasing resistance to axial fluid flow of mobile
and mobilized fluids in the wellbore annulus, between the tubing
and the liner or outer wellbore wall, along a length of the
horizontal well between the at least one injection means and the at
least one production means. A mobilizing fluid is injected through
the injection means. The injection and production means are
operated to control the ratio of the flow resistance in the
wellbore annulus to the flow resistance in the formation, thereby
reducing the amount of the injected mobilizing fluid that is moving
along the wellbore annulus from the injection means to the
production means and increasing the amount of the injected
mobilizing fluid entering and moving through the formation before
being displaced into the well to the at least one production means.
Viscous hydrocarbons are produced using the production means.
[0039] Other aspects and features of the present disclosure will
become apparent to those ordinarily skilled in the art upon review
of the following description of specific examples in conjunction
with the accompanying figures.
BRIEF DESCRIPTION OF DRAWINGS
[0040] The present recovery processes disclosed herein will be
described with reference to the following drawings, which are
illustrative and not limiting:
[0041] FIG. 1 shows a prior art use of a horizontal well with both
injection and production means to recover hydrocarbons.
[0042] FIGS. 2a and 2b show horizontal wells with a constriction
and/or flow conditioner along the annulus of the wellbore.
[0043] FIGS. 3a to 3c show examples of flow conditioners.
[0044] FIG. 4 shows a wellbore with a constriction along its length
and identifies the corresponding change in pressure gradient.
[0045] FIG. 5 is a graph showing the percent oil recovery of a
method according to the present disclosure and conventional
SAGD.
[0046] FIGS. 6a and 6b show a series of packers positioned in the
wellbore to restrict the flow of the injected fluid.
[0047] FIGS. 7a-7d show four examples of the configuration for the
well components using the method set out in the present
disclosure.
DETAILED DESCRIPTION
[0048] The present disclosure provides a process for the recovery
of viscous hydrocarbons from a subterranean reservoir using a
single horizontal well. The hydrocarbons produced using the single
horizontal well recovery process described herein are immobile
hydrocarbons or mobile hydrocarbons which benefit from a mobilizing
method, such as, for example, a thermal recovery process. That is,
while the hydrocarbons may have some mobility, it may not be
sufficient to be commercially effective for production, or the
mobility may be increased with a thermal recovery process, or other
mobilizing method, so as to improve production. In one aspect, the
hydrocarbons are heavy oil and/or bitumen. The recovery process
includes to varying degrees, depending upon the reservoir and
wellbore characteristics, gravity drainage, as well as convective
flow mechanisms. By gravity drainage is meant a process whose flow
mechanisms are predominantly gravity controlled and whose
techniques of operation are largely oriented toward ultimately
maximizing the influence of gravity control because of its inherent
efficiency. By convective flow mechanisms is meant flow and
displacement mechanisms, such as continuous or cyclic convective
displacement.
[0049] In one aspect, the recovery process is a thermal or thermal
and solvent process. In such a process, steam, light hydrocarbons,
hot water, or suitable combinations thereof may be used as the
injection fluid. Further, these injection fluids, such as steam and
light hydrocarbons, may be injected as a mixture or as a succession
or alternation of fluids. Examples of light hydrocarbons include
C.sub.3 to C.sub.10 hydrocarbons such as propane, butane and
pentane.
[0050] Although the present disclosure refers to recovery processes
such as thermal or solvent recovery processes, it will be
understood by a skilled person that the present system and method
will function beneficially for a broad range of in situ recovery
processes including both thermal and non-thermal processes.
Examples of in situ recovery processes which may be used with the
present system and method and in which these fluid re-distribution
principles may be beneficially applied include those which rely,
either singly or in combination, on the injection of steam,
solvents, water, surfactants, and non-condensing gases including
both oxidizing and non-oxidizing gases.
[0051] The method uses a single horizontal well. In one aspect, a
horizontal well implies a well that is substantially or
predominantly horizontal, but may include sections or segments that
are not horizontal. The lack of horizontality over portions or
segments of the well length may occur as a result of technology
limitations, or may be intentional, for example when steering the
well path so that it avoids a particular geological feature, or so
that it creates a structural low point for fluid accumulation, such
as a sump. This characterization of a well as horizontal,
notwithstanding possible deviations from horizontality over
segments or portions of the well length, is well known to those
skilled in the art.
[0052] Further, a single horizontal well may include an individual
wellbore whose openings to the reservoir have been configured to
allow for both injection and production.
[0053] The single horizontal well may also include equipment, such
as multiple strings of tubulars, centralizers, packers, bridge
plugs, sliding seal assemblies, valves, pumps, and liners which may
be necessary to operate the well in this mode. In addition, the
tubulars may include features, such as slots or perforations, or
other types of opening, which provide means of egress from and
ingress into those tubulars. Although reference may be made herein
to wellbores, liners, or other components of a well, these
references are not limiting and will be understood by a person
skilled in the art to be applicable to wellbore construction and
equipment as may be appropriate for a particular reservoir.
[0054] The horizontal well used in the present recovery process
includes an injection means such as, for example, an interval along
the horizontal liner which is open to injection into the reservoir
of a fluid or fluids that are capable of mobilizing, or enhancing
the mobility of, a viscous hydrocarbon, such as bitumen, upon
contact. The recovery process also includes a production means such
as, for example, a separate interval along the horizontal liner
which is open to production from the reservoir into the wellbore of
mobile or mobilized fluids. Although described in the singular for
purposes of simplicity, there may in fact be a plurality of
injection means and a plurality of production means along the
wellbore. The injection and production means are spaced apart from
each other along the length of the well. In one aspect, they are
positioned at or near opposite ends of the well. In an alternative
aspect, they are positioned along the length of the well at closer
positions. Their distance is determined by a number of factors
including the reservoir characteristics, mobility of the
hydrocarbons, possibility for short circuiting of the injected
fluids from the injection means to the production means, and the
extent of recovery within the wellbore. Examples are discussed
below.
[0055] In one aspect, the injection and/or production operations
may be continuous and/or simultaneous. In a further aspect, the
injection and/or production operations may proceed concurrently. In
a further aspect, the injection and/or production operations may
proceed on an interrupted basis, including a cyclic basis. In a
further one aspect, the injection and production means are isolated
from each other in the wellbore. In a further aspect, the area in
the formation adjacent an injection means is absent an induced
fracture.
[0056] In one aspect, the injection operation may involve the
injection of a single fluid or fluid type. In one aspect, the
injection operation may involve two or more fluids or fluid types.
Where two or more fluids, or fluid types, are being injected, their
injection may occur concurrently or sequentially.
[0057] In a single horizontal well operation for the recovery of a
high viscosity hydrocarbons, it is necessary to mitigate the
tendency of injected fluids to preferentially move along the
wellbore annulus instead of entering the reservoir. This entails
modification of the axial fluid resistance path, primarily within
the wellbore annulus, although it can also include modification of
the fluid resistance path within the reservoir itself in the
immediate vicinity of the wellbore. Modification of fluid
resistance within the wellbore can entail the configuration and
deployment of wellbore features and equipment, as will be described
subsequently. Modification of fluid resistance within the reservoir
will inevitably occur as a result of operations that are
implemented following modifications to fluid resistance within the
wellbore. In addition, however, modifications to the reservoir may
be implemented independently. For example, recovery process
start-up may be accelerated and early performance efficiency of the
recovery process may be enhanced by introducing one or more
mobilizing fluids, such as steam or solvent, along a substantial
portion or the entire open length of the horizontal well.
[0058] The process for a single horizontal well is intended to
ensure that mobilizing fluids, while traversing the path of egress
from the wellbore into the reservoir via the injection means to
ingress into the wellbore from the reservoir via the production
means, enter the reservoir in significant quantities during the
course of that traverse and mobilize viscous hydrocarbons, such as
bitumen. Thus, the fluid resistance within the wellbore is
increased so that a greater percentage of the mobilizing fluid is
directed or diverted into the reservoir rather than along the
wellbore. In certain aspects, the present disclosure provides means
of increasing the fluid resistance within the wellbore by using
either a medium that behaves as a continuum within and along the
wellbore annulus or, alternatively, an impediment or a series of
discrete wellbore impediments, including sealing elements, that are
located in specific relation to openings along the wellbore and
that can be activated either concurrently or sequentially, or a
combination of both alternatives. Within the context of this
disclosure, use of terms such as "impediment" or "sealing element"
can imply a means that creates a complete restriction to flow or a
partial restriction to flow.
[0059] In one aspect, the means of increasing the fluid flow
resistance, namely the primarily axial flow in the annulus of the
injected fluids and of the mixture of mobile and mobilized fluids,
traverses a length of the wellbore and engenders a variable
frictional energy loss along that length, so that a greater
percentage of the injected fluids is diverted away from flow in the
wellbore annulus and instead flows into the reservoir. The device
is of substantial length compared with, for example, the effective
length of a packer, and is instrumental in inhibiting the fluid's
re-entry into the wellbore from the reservoir after traversing the
reservoir for only a short distance. One example is a flow
conditioner. The flow conditioner extends along the longitudinal
axis of the wellbore. It is positioned in the wellbore annulus
between the tubing and the liner. It may taper from one end to the
other providing a constriction in the wellbore annulus and/or it
may have externally extending projections that will interfere with
fluid flow and provide resistance to the flow path of a fluid in
the wellbore annulus. Due to the frictional energy loss, this flow
path resistance will cause the fluid to flow into the reservoir
rather than through the wellbore annulus. As a result, a greater
amount of injected fluid will enter the reservoir than in systems
where no impediment is placed in the wellbore annulus or where only
a single packer located between proximate injection and production
intervals is used as an impediment.
[0060] Because of the length of the flow conditioner, the injected
fluids, along with mobile and mobilized hydrocarbons and associated
reservoir fluids, will re-enter the wellbore further downstream
after the flow conditioner, which therefore reduces or prevents
short circuiting of the injected fluid from the injection means to
the production means of the wellbore.
[0061] In a further aspect, increasing fluid resistance in the
wellbore involves reducing the size of the annular space between
the outside of the tubing and the inside of the casing or liner so
that fluids flowing in this reduced annular space will experience
an increased resistance to fluid flow. This reduced annular space
may be achieved, for example, by increasing the diameter of the
tubing, decreasing the diameter of the casing or both. Preferably
the reduced annular space is used in combination with a sealing
element such as a packer positioned between the injection and
production means or a constriction element in the annulus which may
include a sealing element that is not fully deployed.
[0062] In a further aspect, the means of increasing the flow
resistance is a series of impediments placed in the wellbore. These
may be operated concurrently or sequentially. For example, the
impediments may be a series of sealing elements such as packers
placed along the wellbore at selected distances. In one aspect,
production openings are open along the wellbore situated in the
intervening distances between the sealing elements. The sealing
elements may be operated in series, with the first set before the
initial injection of fluid. Once the injected fluid short circuits
the first sealing element, the second sealing element is set. As
hydrocarbons in the reservoir are produced and the injected fluids,
along with mobile and mobilized hydrocarbons and associated
reservoir fluids, short circuit the sealing elements, further
sealing elements are set, again forcing the injected fluids and
mobile or mobilized fluids to traverse a greater portion of its
flow path within the reservoir and re-enter the wellbore further
downstream. Any number of sealing elements can be used and can be
set in series or concurrently, until either the desired flow
configuration is established or until physical or other limitations
are encountered and preclude further deployment.
[0063] In one aspect, the sequential deployment of sealing
elements, such as packers, may involve the activation of successive
sealing elements, each of which is situated at a particular fixed
location along the tubing, and such that the tubing itself is
stationary within the well throughout this operation. In one
aspect, one may employ as few as two packers to accomplish a
similar effect by carrying out a number of sequential withdrawals
or re-positionings of the tubing, each time disengaging and then
re-engaging the packers in their new positions within the wellbore.
In this aspect, when the tubing is re-positioned within the
wellbore, the packers may remain in their current positions along
the tubing string, or may be re-positioned relative to the tubing
string itself.
[0064] The staging of the sequence of packers, whether as
stationary sealing elements along a stationary tubing string, or as
stationary or moveable sealing elements along a tubing string that
is successively re-positioned, as described above, may be guided by
the mobility of the hydrocarbons in the vicinity of the packer.
Specifically, a packer is activated, or re-positioned and
activated, at a particular location along the wellbore only after
the hydrocarbons in the reservoir corresponding to a location
immediately downstream of the packer (i.e., between the packer and
the proximal end of the horizontal well) have become mobile. Absent
that hydrocarbon mobility, the heating fluids which advance in the
proximal direction through the reservoir, over the interval of
wellbore occupied by the packer, may lack a means of displacing the
hydrocarbons into the wellbore downstream of the packer.
[0065] Alternatively, the impediments may be set simultaneously so
that the flow resistance in the wellbore forces the injected fluid
into the reservoir for the length of the wellbore containing the
sealing elements.
[0066] In one aspect, the wellbore configuration may include
constrictions within the wellbore, allowing some injected fluid to
pass. This may be achieved in one example by partially setting the
sealing elements, rather than full sealing elements. Constrictions
in the wellbore may also be used with flow conditioners to further
increase the fluid flow resistance in the wellbore. Further, the
wellbore may include a combination of flow conditioners with
packers or other sealing elements.
[0067] In a further aspect, the wellbore may be equipped with one
or more spaced apart devices located along the length of the
horizontal tubing which modify or impede, but do not altogether
prevent, axial flow along and within the annulus. For example, the
wellbore may include a number of spaced apart devices such as
packers which may seal off the annulus at the location of those
devices or fracture cups which may largely cover the cross-section
of the annular area by means of frictional contact with the
interior of the liner or casing rather than a seal. Irrespective of
the particular device selected, the device may be equipped with
axially oriented flow conduits, such as nozzles, one or more of
which may penetrate the device so that, notwithstanding the
tendency of the device to impede or prevent axial flow, a measure
of flow will occur through the axially oriented flow conduit(s)
embedded within that device.
[0068] In one example, injected fluids may exit the tubing near the
toe of the well and may tend to flow back along the annulus towards
the heel. A series of spaced apart devices, such as packers or
fracture cups, are located within the annulus, with each such
device having embedded within it one or more axially oriented
nozzles. The geometry of the nozzle(s), and in particular their
diameter, may be designed so that the nozzle(s) presents a major
restriction to flow along the annulus, thereby diverting a major
portion of the injected fluid upward or outward into the reservoir.
The nozzles' geometry may be selected so as to create the
conditions for sonic (i.e., critical) flow within the nozzle.
Fluids which pass through these nozzles may merge on the downstream
side of the nozzles with fluids that had been diverted into the
reservoir on the upstream side of the nozzles and which
subsequently entered the annulus from the reservoir on the
downstream side of the nozzles, bringing with them reservoir fluids
which have been mobilized. The resulting fluid mixture on the
downstream side of the first set of nozzles will move towards the
second device within which one or more nozzles are embedded. Again,
a portion of the fluids approaching the second set of nozzles may
be diverted into the reservoir while a portion flows through the
nozzle(s) in the second device. The nozzles embedded in the second
device may differ in geometry and number from the nozzles embedded
in the first device. The nozzle(s) embedded in the second device
may be configured so as to offer less resistance to fluid flow than
the nozzle(s) in the first device. The nozzles in the second device
may be configured so that flow of fluids through them is
sub-critical. Additional sealing or frictional devices may be
located along the length of the annulus with embedded nozzles.
[0069] In a further aspect, the frictional devices may be designed
and configured so that the geometry and size of the gap or aperture
between the device and the surrounding casing or liner will impede
or restrict flow in a specific manner, thereby acting in place of,
or in addition to, embedded nozzles.
[0070] In a further aspect, the wellbore may be configured so that
steam is injected into the annulus and reservoir at a multiplicity
of locations. For example, steam may be injected into two tubing
strings, each positioned with its toe at a different location
within the wellbore. Thus, in one example, steam is injected into a
first tubing string which terminates in the region of the wellbore
closer to the heel, while steam injection in a second tubing string
exits the tubing closer to the toe of the well. For each such
string of tubing, a series of devices as described herein are
placed so as to both encourage flow of injected steam into the
reservoir and allow return of mobile and mobilized fluids into the
wellbore for subsequent production.
[0071] The means of increasing the flow resistance in the wellbore
may consist of one of the options set out herein or a combination
of them. For example, in further aspects, the present method
provides a constriction element and a flow conditioner; a sealing
element and a flow conditioner; or a series of sealing elements
acting as impediments within the wellbore. These combinations
provide an increase in the frictional energy loss within the
wellbore annulus. The result is redirecting more of the injected
fluid into the reservoir rather than through the wellbore annulus,
increasing the recovery of the hydrocarbons, and improving the
steam oil ratio.
[0072] In a further aspect, no openings are positioned in the
wellbore between the sealing elements. The casing or liner will
have wall openings, or groups of wall openings with intervening
intervals containing no wall openings. The blanked off intervals
between groups of casing or liner openings provide interior casing
or liner wall locations against which sealing elements, such as
packers, may be inflated or deployed.
[0073] The design of the casing or liner in respect of the
locations of its openings, or groups of openings, can involve
considerations not only of the implementation of the present system
and method, but also of the use of techniques employed prior to the
implementation of the present system and method to condition the
near-wellbore vicinity by enhancing mobility. One such technique to
enhance mobility in the near-wellbore region involves injection of
a solvent, such as xylene. An alternative technique for enhancing
near-wellbore mobility involves a geomechanical approach whereby
applied pressure causes a re-orientation of the sand grains and
consequent mobility improvement. A traditional technique for
enhancing mobility in the near-wellbore vicinity employs heat
transfer primarily by conduction and involves injecting a hot
fluid, such as steam, down to the toe of the tubing and thence back
around through the annulus and ultimately to the surface, the
reservoir in the near-wellbore vicinity being heated thereby as a
consequence of the circulating wellbore fluids. Such techniques,
often referred to as accelerated start-up techniques, may entail
injection into the reservoir of limited fluid volumes, and may
employ openings along a substantial length of the casing or liner.
Those skilled in the art will be capable of situating the groups of
wall openings in the casing or liner so that both the step of
increasing mobility in the near-wellbore vicinity and the
subsequent step of practicing the methods and systems of the
present disclosure are accomplished.
[0074] The present method with its governance of friction in the
annular region of the wellbore as described herein permits
injection and production at high rates. This is in contrast to
Nzekwu, which requires that production is confined to low rates so
as to avoid low pressures in the vicinity of the pump, with
consequent flashing of steam, and reduction in pump efficiency.
Specifically, Nzekwu requires this restriction so that a liquid
level can build in the vicinity of the pump in the vertical part of
the primarily horizontal well.
[0075] FIG. 1 shows a prior system for a single horizontal well 1
in a viscous hydrocarbon reservoir. In attempting to mitigate the
problem of short-circuiting of the injected fluid, such as steam,
into and along the wellbore, the well 1 uses a single packer 7
placed near the distal end 5 (i.e. toe) of the well in the annular
region between the tubing 2 and the casing or liner 3. The packer
is used as a sealing element, providing an impediment to the
injected fluid. In this example, steam is injected down the tubing
2 to the distal end 5 of the well where it exits the tubing
upstream of the packer 7. There, openings in the casing or liner
are provided so that the steam, prevented from moving downstream
within the annular region by the presence of the packer 7, will
enter the reservoir. However, as explained above, placement of a
single packer provides only a localized and temporary mitigation of
the short-circuiting problem inasmuch as the steam, after a brief
sojourn in the reservoir, and after limited contact with and
mobilization of viscous hydrocarbons, can re-enter the wellbore
through openings located in the casing or liner downstream of the
packer, whence it will be produced without having maximized its
mobilization potential within the reservoir.
[0076] In contrast to this prior system, in the present disclosure,
the process in one aspect uses a means for increasing flow
resistance in the wellbore annulus to prevent or minimize short
circuiting of the injected fluid and allows it to stay in contact
with the reservoir for a longer period of time to improve
mobilization of the fluids. In another aspect, the process
increases flow resistance in the wellbore annulus by using
impediments or sealing elements, such as packers, to prevent or
minimize these short-circuiting tendencies.
[0077] FIGS. 2a and 2b illustrate specific aspects of the present
invention where, instead of a single discrete impediment to flow
within the wellbore, a flow conditioner is placed in the wellbore
which traverses a substantial length of the wellbore and which
engenders a variable frictional energy loss along that length. As a
result, a greater percentage of the injected fluids are diverted
away from the wellbore and into the reservoir. FIGS. 2a and 2b
illustrate some examples of a flow conditioner 9. As shown in FIG.
2a, the device can be tapered to increase the frictional resistance
as the injected fluid moves toward the impediment, i.e. the packer
7. Alternatively, as shown in FIG. 2b, the device may be finned,
with multiple ribs extending into the annulus area to provide
increased friction to the flow of the injected fluid. Flow
conditioners may have a series of ribs or suitable other structures
positioned perpendicular to the longitudinal axis of the wellbore
or may have multiple ribs extending along the longitudinal axis of
the wellbore. Further, the multiple ribs may be continuous,
segmented, or divided into bristle-like formations. FIGS. 3a to 3c
show some examples of commercially available flow conditioners. The
multiple ribs or other suitable structures along the flow
conditioner interfere with the flow of the injected fluid through
the wellbore annulus between the tubing and the casing. FIG. 2B
also uses a packer with the flow conditioner to further increase
the flow resistance in the wellbore. Packers or other sealing
elements may be used with the flow conditioners or they may be used
on their own. Since the frictional energy loss is increased, the
injected fluid will be diverted into the reservoir. This increases
the amount of injected fluid that enters the reservoir and results
in an increase in the mobilization of hydrocarbons in the
reservoir.
[0078] One or more flow conditioners may be positioned in the
wellbore annulus, between the tubing and the liner, at the
injection end of the casing, upstream of the packer. Alternatively
or in addition thereto, one or more flow conditioners may be
positioned in the wellbore annulus on the production end of the
wellbore downstream of the packer. FIGS. 2a and 2b show flow
conditioners 9 positioned on both the upstream and downstream sides
of the packer in the annulus in the wellbore. By providing the flow
conditioners downstream of the packer 7, less injected fluid will
enter the wellbore downstream on the production side near the
packer. Instead, the injected fluid will stay in the reservoir
where the frictional energy loss is less, and the injected fluid
will enter the production side of the casing further downstream
from the packer. This reduces and/or prevents short circuiting of
the injected fluid and increases the amount of the reservoir in
contact with the injected fluid.
[0079] As shown in FIG. 4, the flow conditioners 9 are positioned
within the wellbore upstream and downstream of the injection and
production means. They are tapered along the longitudinal wellbore
axis so that the upstream flow conditioner increases in diameter as
it extends towards the heel of the wellbore. An adjacent flow
conditioner is positioned downstream of the upstream flow
conditioner and its diameter decreases as it extends along the
longitudinal axis of the wellbore. These flow conditioners provide
a constriction point in the wellbore limiting the flow of injected
fluid through the annulus in the wellbore. The flow conditioners
moderate the pressure drop across the constriction. The pressure
drop is higher than the pressure drop across the sand face. As a
result, the injected fluid will spread into the reservoir rather
than flow along the wellbore annulus. The injected fluid will not
reenter the wellbore until the flow resistance in the wellbore
decreases, becoming less than that in the reservoir, near the
downstream end of the downstream flow conditioner. This also
prevents short circuiting of the injected fluid from the injection
side to the production side.
[0080] The use of flow conditioners within the wellbore may also
allow for a reversible recovery process without reconfiguration of
the wellbore flow conditioners. For example, the injected fluid may
be injected at the toe end of the wellbore initially with
production of the hydrocarbons near the heel of the wellbore.
However, in a later stage, this may be reversed and the fluid may
be injected near the heel of the wellbore and produced from the toe
end of the wellbore. As shown in FIGS. 2a and 4, the flow
conditioners are positioned so that a taper occurs on both the
upstream and downstream ends of the wellbore. In FIG. 2b, the flow
conditioners are present on both sides of the packer providing
multiple ribs or other structures which extend into the wellbore on
either side of the packer. This allows the flow conditioners to
provide an impediment to the flow of the injected fluid regardless
of whether it is injected near the toe of the well with production
near the heel of the well or whether injection occurs near the heel
of the wellbore with production near its toe. It is contemplated
that the process may be initiated in one direction and then
reversed after a period of hydrocarbon recovery has occurred.
[0081] A further example of means of increasing the flow resistance
in the wellbore is shown in FIGS. 6A and 6B. These figures show a
series of sealing elements such as packers between which are
openings to the reservoir at selected intervals along the length of
the wellbore. A first packer is set as a sealing element, creating
an impediment to the flow of injected fluid through the wellbore.
The remaining sealing elements are not set and do not form
impediments to fluid flow in the wellbore. The injected fluid will
enter the wellbore, preferably at or near the distal end, and be
forced into the reservoir. As hydrocarbon recovery occurs, the
injected fluid will short circuit and re-enter the wellbore
immediately downstream of the packer as shown in FIG. 6A. To
improve hydrocarbon recovery and lengthen the time that the steam
stays in the reservoir, a second packer, further along the wellbore
from the first packer, and towards the proximal end, is now set as
a sealing element, as shown in FIG. 6B. This provides a longer
length of the wellbore where the injected fluid cannot travel. As a
result, the fluid will remain in the reservoir until it reaches
downstream of the second set packer, improving hydrocarbon
recovery. Once the hydrocarbon recovery progresses and injected
fluid begins to short circuit this second packer, a third packer
will be set as a sealing element, again limiting the section of the
wellbore where the injected fluid can travel. Any number of packers
or other sealing elements can be used along the length of the
wellbore. Although FIGS. 6A and 6B show the packers being set in
series as hydrocarbon recovery progresses, they can also be set
simultaneously. Further, although FIGS. 6A and 6B do not show the
use of flow conditioners, they may be used in conjunction with one
or more of the sealing elements. For clarity, FIG. 7 shows four of
the earlier described examples for the well components
configuration using the present method. FIG. 7A shows a system
using sequentially deployed packers within the wellbore annulus.
FIG. 7B shows a system using one packer and a constricted annulus.
FIG. 7C shows a system using nozzles of varying sizes within the
packer/sealing elements and where the fluid is injected at a single
point. FIG. 7D shows a system using nozzles of varying sizes within
the packer/sealing elements and where the fluid is injected at two
points.
[0082] The above approach involving sealing elements may be
modified to accomplish the same objective but in examples involving
as few as two sealing elements. In one aspect, described with
respect to packers as the sealing elements, a first packer is set,
mobilizing fluids are injected into the reservoir, those fluids
eventually short circuit the first packer and re-enter the
wellbore, whereupon a second packer further along the wellbore from
the first packer, and directionally closer to the heel, is
deployed. However, beyond this point, instead of deploying
successive packers, as described in the above approach, the entire
assembly involving the tubing string, and the two packers, is moved
axially so that the end of the tubing is now displaced from its
original position along the length of the wellbore and is located
further away from the toe. In this example, subsequent engagement
of the first and thence the second packer will allow the axial
progress of the heated front from the toe towards the heel, both in
the reservoir and in the wellbore. As a further variation of this
approach, when the tubing is re-located to a new position along the
wellbore, it may be opportune to actually re-position the two
packers relative to the tubing string itself. This may involve
removing the tubing string from the well, re-positioning the
packers relative to the toe of the tubing string, and possibly
relative to each other, and then re-installing the tubing within
the well and positioning it at its new location.
[0083] In one aspect, the injection and production steps in the
recovery process of the present disclosure may entail the
imposition of a higher pressure differential between injection and
production means than would be the case for gravity thermal
recovery processes, such as SAGD. This would provide a convective
recovery mechanism, in addition to gravity drainage.
[0084] The discussion herein is concentrated on a single horizontal
well in isolation. The present disclosure also includes the use of
laterally adjacent single horizontal wells, with appropriate well
spacing between them, so that each effectively recovers viscous
hydrocarbons from its region. Mathematical modeling has
demonstrated that further efficiencies can be realized by aligning
these adjacent wells appropriately. In one example, if two
laterally adjacent wells are aligned in parallel so that the toe
end of one well is closest to the heel end of its neighbor, then
concurrent operation of the two wells in accordance with the
principles of this disclosure will further improve performance
because of increased volumetric sweep efficiency, or
conformance.
[0085] Further, although the above discussion refers to the
injection means being positioned at the toe of the horizontal well
and the production means positioned at the heel of the well, these
positions may be reversed or altered for recovery of the
hydrocarbons.
[0086] In a comparison of the present method with conventional
SAGD, 800 m long wells were used. The SAGD well pairs were spaced
100 m apart while the single horizontal wells of the present method
were spaced 50 m apart, providing the same effective spacing. Using
a thin pay of 10 m, simulations were run to show the percent oil
recovery. The processes were optimized with solvent addition. The
results are shown in FIG. 5. For optimization, in the single well
using the present method, 5% hexane was added for 1 year while in
the SAGD process, 1.5% hexane was added for 1 year. While these
amounts of hexane differ, they represent equivalent amounts of
injected hexane using the two processes. The example using the
single well in the present method injects only at the toe end of
the well while the SAGD process injects along the length of the
well. As a result, the higher concentration of the injected hexane
in the single well example is an equivalent amount as compared to
the lower concentration of the injected hexane in the SAGD example.
The graph shows that the present method provides for an increased
oil recovery over time as compared to a conventional SAGD process.
Recovery can be further improved by using accelerated start up
process, examples of which are known in the art.
[0087] The methods and systems described in this disclosure are
intended to be capable of operating independently of any adjacent
or neighboring wells or well groups. As such, the methods and
systems of the present disclosure are applicable in a virgin
reservoir. However, it will be readily understood by those skilled
in the art that single wells may be strategically located, and
single well recovery processes may be operated within a reservoir
to harvest hydrocarbons which have been or would otherwise be
bypassed by nearby or surrounding in situ recovery operations.
Wells employed in this capacity are sometimes referred to as infill
wells. The methods and systems of the present disclosure may be
used in that capacity.
[0088] Reference is made to exemplary aspects and specific language
is used herein. It will nevertheless be understood that no
limitation of the scope of the disclosure is intended. Alterations
and further modifications of the features described herein, and
additional applications of the principles described herein, which
would occur to one skilled in the relevant art and having
possession of this disclosure, are to be considered within the
scope of this disclosure. Further, the terminology used herein is
used for the purpose of describing particular aspects only and is
not intended to be limiting, as the scope of the disclosure will be
defined by the appended claims and equivalents thereof. All
publications, patents, and patent applications mentioned in this
specification are herein incorporated by reference to the same
extent as if each individual publication, patent or patent
application were each specifically and individually indicated to be
incorporated by reference.
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