Note: Descriptions are shown in the official language in which they were submitted.
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TWO-STAGE DOWNHOLE OIL-WATER SEPARATION
BACKGROUND
[00011 This section provides background information to facilitate a better
understanding of the
various aspects of the present invention. It should be understood that the
statements in this
section of this document are to be read in this light, and not as admissions
of prior art.
[00021 Oil well production can involve pumping a well fluid that is part oil
and part water, i.e.,
an oil-water mixture. As an oil well becomes depleted of oil, a greater
percentage of water is
present and subsequently produced to the surface. The "produced" water often
accounts for at
least 80 to 90 percent of a total produced well fluid volume, thereby creating
significant
operational issues. For example, the produced water may require treatment
and/or re-injection
into a subterranean reservoir in order to dispose of the water and to help
maintain reservoir
pressure. Also, treating and disposing produced water can become quite costly.
[00031 One way to address those issues is through employment of a downhole
device to separate
oil-water and re-inject the separated water, thereby minimizing production of
unwanted water to
surface. Reducing water produced to surface can allow reduction of required
pump power,
reduction of hydraulic losses, and simplification of surface equipment.
Further, many of the
costs associated with water treatment are reduced or eliminated.
[00041 However, successfully separating oil-water downhole and re-injecting
the water is a
relatively involved and sensitive process with many variables and factors that
affect the
efficiency and feasibility of such an operation. For example, the oil-water
ratio can vary from
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well to well and can change significantly over the life of the well. Further,
over time the
required injection pressure for the separated water can tend to increase.
SUMMARY
[0005] A downhole fluid separation system according to one or more aspects of
the present
disclosure comprises a first oil-water separator comprising an inlet, a first
water outlet and a first
oil outlet; and a second oil-water separator comprising an inlet, a second
water outlet and a
second oil outlet, wherein the inlet of the second oil-water separator is
connected in hydraulic
series to the first water outlet.
[0006] The first oil-water separator may comprise one selected from the group
of a static
separator and a dynamic separator; and the second oil-water separator may
comprise one selected
from the group of a static separator and a dynamic separator. In at least one
embodiment the first
oil-water separator and the second oil-water separator are of the same type of
separator.
[0007] According to one or more aspects of the present disclosure a system
comprises a wellbore
in communication with a production zone and an injection zone; a pump
positioned in the
wellbore having an inlet in fluid communication with a well fluid; a first
separator having an
inlet, a first water outlet and a first oil outlet, the inlet in fluid
connection with a pump discharge;
and a second separator having an inlet, a second water outlet and a second oil
outlet, the inlet of
the second separator connected in hydraulic series to the first water outlet
and the second water
outlet in fluid communication with the injection zone.
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[0008] A method for downhole oil-water separation, according to one or more
aspects of the
present disclosure, comprises disposing an oil-water separation system in a
wellbore, the system
comprising a first separator connected in hydraulic series with a second
separator; separating a
well fluid in the first separator into a first injection stream and a first
production stream;
discharging the first injection stream to an inlet of the second separator;
separating the first
injection stream in the second separator into an output injection stream and a
second production
stream; and injecting the output injection stream from the wellbore into an
injection formation.
[0009] The foregoing has outlined some of the features and technical
advantages of the present
invention in order that the detailed description of the invention that follows
may be better
understood. Additional features and advantages of the invention will be
described hereinafter
which form the subject of the claims of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] The present disclosure is best understood from the following detailed
description when
read with the accompanying figures. It is emphasized that, in accordance with
standard practice
in the industry, various features are not drawn to scale. In fact, the
dimensions of various
features may be arbitrarily increased or reduced for clarity of discussion.
[0011] Figure 1 is a schematic diagram of a downhole oil-water separation
system, according to
one or more aspects of the present disclosure
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[0012] Figure 2 is a schematic of an embodiment of a downhole oil-water
separation system
according to one or more aspects of the present disclosure disposed in a well
having an injection
zone positioned below the production zone.
[0013] Figure 3 is a schematic of another embodiment of a downhole oil-water
separation
system according to one or more aspects of the present disclosure disposed in
a well having an
injection zone positioned below the production zone.
[0014] Figure 4 is a schematic of an embodiment of a downhole oil-water
separation system
according to one or more aspects of the present disclosure disposed in a well
having the
production zone positioned below the injection zone.
DETAILED DESCRIPTION
[0015] It is to be understood that the following disclosure provides many
different embodiments,
or examples, for implementing different features of various embodiments.
Specific examples of
components and arrangements are described below to simplify the present
disclosure. These are,
of course, merely examples and are not intended to be limiting. In addition,
the present
disclosure may repeat reference numerals and/or letters in the various
examples. This repetition
is for the purpose of simplicity and clarity and does not in itself dictate a
relationship between
the various embodiments and/or configurations discussed. Moreover, the
formation of a first
feature over or on a second feature in the description that follows may
include embodiments in
which the first and second features are formed in direct contact, and may also
include
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embodiments in which additional features may be formed interposing the first
and second
features, such that the first and second features may not be in direct
contact.
[0016] As used herein, the terms "up" and "down"; "upper" and "lower"; "top"
and "bottom";
and other like terms indicating relative positions to a given point or element
are utilized to more
clearly describe some elements. Commonly, these terms relate to a reference
point as the surface
from which drilling operations are initiated as being the top point and the
total depth of the well
being the lowest point, wherein the well (e.g., wellbore, borehole) is
vertical, horizontal or
slanted relative to the surface.
[0017] In this disclosure, "hydraulically coupled" or "hydraulically
connected" and similar terms
(e.g., pneumatic, fluidic), may be used to describe bodies that are connected
in such a way that
fluid pressure may be transmitted between and among the connected items. The
term "in fluid
communication" is used to describe bodies that are connected in such a way
that fluid can flow
between and among the connected items. It is noted that hydraulically coupled
may include
certain arrangements where fluid may not flow between the items, but the fluid
pressure may
nonetheless be transmitted. Thus, fluid communication is a subset of
hydraulically coupled.
[0018] The present disclosure is directed to downhole oil-water separation
(e.g., processing)
systems. According one or more aspects of the present disclosure, downhole oil-
water
separation systems are provided for wells having a water cut of 50 percent or
greater. According
to one or more aspects of the present disclosure, downhole oil-water
separation systems are
provided for water cuts of about 80 percent and greater. According to one or
more aspects of the
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present disclosure, downhole oil-water separation systems are provided to
reduce the oil content
in the injection string below 100 ppm in wells having a water cut of about 80
percent or greater.
[00191 Downhole oil-water separation generally comprises static separation,
utilizing one or
more hydrocyclone liners, and dynamic separation which utilizes a centrifuge
separator rotating
at the same operating speed of an electrical submersible pump ("ESP").
Hydrocyclone liners are
available in different diameters. Small diameter liners, known as deoilers,
have quality
separation performance but are flow rate limited. To overcome the flow rate
limitations of
deoilers, multiple deoilers can be operated in hydraulic parallel. For
example, in surface
operations several hundred deoilers (e.g., 1 inch (2.54 cm) diameter) each
passing a few hundred
barrels ("bbl") per day ("bpd") may be utilized in hydraulic parallel to
handle the required flow
rate. This approach is impractical in downhole applications. Thus, larger
deoilers (e.g., 3 inch
diameter) are often used to boost flow rate capabilities at the expense of
separation performance.
Examples of some present and prior high quality downhole oil-water separation
systems are
disclosed in U.S. Patent No. 5,961, 841 and U.S. Patent Application
Publication Nos.
2009/0242197 and 2009/0056939 which are incorporated herein by reference.
[00201 Figure 1 is a schematic diagram of a downhole oil-water separation
system, generally
denoted by the numeral 10, according to one or more aspects of the present
disclosure. Depicted
system 10 may be generally described as a two-stage separation system, wherein
the first stage
separator and the second stage separator are connected in hydraulic series.
[00211 System 10 comprises a first stage separator 12 (e.g., bulk) and a
second stage separator
14 connected in hydraulic series. The total inlet fluid 16 (e.g., wellbore
fluid, formation fluid) is
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drawn (e.g., injected) into first stage injector 12 through inlet 12a wherein
total inlet fluid stream
16 is separated into a first injection stream 17 comprising the higher water
portion stream of total
inlet stream 16 and a first production stream 18 comprising the higher
hydrocarbon (e.g., oil)
portion. First production stream 18 is discharged from an outlet 18a (e.g.,
oil outlet, production
outlet) and may be directed to the surface as the production outlet stream 20.
First injection
stream 17 is discharged from an outlet 17a (e.g., water outlet, injection
outlet) becomes the inlet
stream (via inlet 14a) to second stage separator 14. First injection stream 17
is separated into the
injection stream 19 and a second production stream 22. Injection stream 19 is
discharged from
an outlet 19a and is injected into an injection zone of the geological
formation surrounding the
well, provided it satisfies the required stream quality. Second production
stream 22 is discharged
through an outlet 22a and may be produced to the surface or discharged to the
wellbore. In
Figure 1, second production stream 22 is depicted produced to the surface as
production outlet
stream 20.
[0022] First production stream 18 may bypass second stage separator 14 and be
produced
directed to the surface (e.g., production stream 20) or it may be combined
with second
production stream 22 for lifting to the surface. Due to the additional
pressure drop from second
stage separator 14, second stage production stream 22 will have a lower
pressure than that of first
production stream 18. Before production streams 18, 22 can be combined, the
pressures must be
balanced, for example via device 24. Device 24 may comprise an apparatus for
reducing the
pressure of first production stream 18 and/or to increase the pressure of
second production
stream 22. For example, device 24 may comprise a pump for boosting the
pressure of second
production stream 22.
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[0023] An example of a pressure balancing device 24 that reduces the pressure
of first
production stream 18 may be integrated for example in first stage separator 12
or second stage
separator 14 or provided in a separate module. Pressure reduction balancing
device 24 may
comprise for example a valve (e.g., fixed or adjustable) to provide the
pressure drop. Device 24
may further comprise a check valve and/or one or more sensors (e.g., gauges)
such as, and
without limitation, flow rate sensors, pressure sensors, and oil-water
concentration gauges.
[0024] According to one or more aspects to the present disclosure, system 10
may be particularly
adapted for use in a well having a water cut of about 50 to 80 percent and
needing a low oil-
content injection stream, for example lower than 500 ppm of oil (e.g., water
cut of about 99.95 %
or lower).
[0025] First stage separator 12 and second stage separator 14 may be of the
same type of
separator (e.g., static, hydrocyclone) or different types of separators. It is
noted that first and or
second stage separator 12, 14 may comprise more than one separator. For
example, a stage
separator may comprise cascades of hydrocyclone liners arranged in hydraulic
parallel.
[0026] An example of a system 10, according to one or more aspects of the
present disclosure,
for providing an injection stream to a range of about 100 ppm from a high
water-cut (e.g., greater
than about 80 percent water) total inlet stream 16 is now described with
reference to Figure 1.
First stage separator 12 separates total inlet fluid stream 16 into a first
injection stream 17 having
an oil-in-water concentration of about 500 ppm. First injection stream 17 is
introduced in
hydraulic series to second separator stage 14. Second stage separator 14
separates first injection
stream 17 into an outlet injection stream 19 having an oil-in-water
concentration in the range of
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100 ppm. In this example, second stage separator 14 may comprise one or more
hydrocyclone
separators.
[0027] An example of a downhole oil-water separation system 10 for use in a
low water cut
(e.g., about 50 to 80 percent water) is now described with reference to Figure
1. Total inlet
stream 16 (e.g., wellbore fluid) comprises a water cut in the range of about
50 to 80 percent
water. Inlet stream 16 is taken into first stage separator 12 (e.g., bulk
hydrocyclone liners)
wherein a first injection stream 17 having a water cut, for example, of about
99 percent (e.g., 1
percent oil-in-water concentration or 10,000 ppm oil-in water) is provided.
First injection stream
17 is passed through second stage separator 14 (e.g., a single static
separator) which provides a
injection outlet stream 19 comprising an oil-in-water concentration reduced
from about 10,000
ppm (e.g., 1 percent) down to approximately 500 ppm of oil-in-water
concentration (e.g., 0.05
percent).
[0028] Figure 2 is a schematic of a downhole oil-water separation system 10
according to one or
more aspects of the present disclosure disposed in a well 26. System 10 is
disposed downhole in
wellbore 28 of well 26. In this embodiment, the production zone 30 is located
above the
injection zone 32 relative to surface 34 of well 26. Total inlet stream 16 is
formation fluid that is
produced from production zone 30 into wellbore 28. Injection stream 19 is
injected into
injection zone 32.
[0029] Depicted system 10 comprises first stage separator 12 connected in
hydraulic series with
second stage separator 14 and a downhole pump 36. Downhole pump 36 is depicted
as an
electrical submersible pump comprising a motor 38. Total inlet fluid 16 is
drawn into inlet 40 of
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pump 36, thus into the separation process flow path, and discharged from pump
outlet 36a into
inlet 12a of first stage separator 12. Total inlet fluid 16 is separated in
first stage separator 12
into a first injection stream 17 and a first production stream 18. First
injection stream 17 and
first production stream 18 pass through a flow control manifold 42 wherein
first injection stream
17 is directed through a conduit 44 (e.g., bypass conduit) to second stage
separator 14. In this
embodiment, first production stream 18 is produced to the surface 34 as output
production
stream 20 through tubing 46.
[0030] In second stage separator 14, depicted as a deoiler in Figure 2, first
injection stream 17 is
separated into an output injection stream 19 and a second production stream
22. In this
embodiment, the oil portion (e.g., second production stream 22) is discharged
from second stage
separator 14 into the annulus 48 of wellbore 28 above packer 50. Packer 50
isolates injection
zone 32 from production zone 30 and inlet 40 of the oil-water separation
process path. Annulus
48 is defined between the wellbore wall 52 (e.g., casing) and the exterior of
conduit 44.
Injection stream 19, discharged from second stage separator 14, flow through
the bore of conduit
44 across packer 50 where it is injected into formation zone 32.
[0031] Depicted system 10 comprises a sensor system 54 (e.g., package,
module). In the
embodiment depicted in Figure 2, sensor system 54 is disposed down stream of
second stage
separator 14 and upstream of injection zone 32 in hydraulic communication with
injection stream
19. Sensor system 54 may be utilized for monitoring a variety of
characteristics related to the
downhole fluid processing, including pressure, temperature, chemistry,
vibration, fluid
composition, and other characteristics. Examples of sensors that can be
incorporated into sensor
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system 54 include oil-in-water sensors, sand-in-water sensors, flow meters,
pressure sensors,
chemistry sensors, and vibration sensors that enable the system operation to
be optimized. In
some applications, sensor system 54 may enable real-time corrections based on
data provided by
the sensor system to reduce the risk of system failure or damage.
[0032] For a variety of reasons, including local regulations, it may be
desirable to limit oil-in-
water levels for certain applications. The sensor system enables monitoring to
ensure the
separated water (e.g., outlet injection stream 19) does not exceed the
desired/required level of oil
in the water component. The sensor system can be designed to provide an alarm
or other
indication to an operator to enable adjustment to the downhole fluid
processing parameters. For
example, adjustments can be made to the backpressure at the stage separators
via the flow-
restrictor, or adjustments can be made to other components to regulate well
head pressure, to
adjust speed of an electric submersible pump, or to make other adjustments.
Furthermore,
monitoring of the oil-in-water content of outlet injection stream 19 can be
useful in limiting
potentially harmful impacts on the injection zone. The sensor system provides
operators with
advance notice to enable the taking of corrective action, such as scheduling a
stimulation
procedure before the injection zone becomes severely plugged.
[0033] Figure 3 is a schematic diagram of another embodiment of a downhole oil-
water
separation system 10 according to one or more aspects of the present
disclosure. In the depicted
embodiment, injection zone 32 is disposed below production zone 30 relative to
surface 34.
System 20 comprises a packer 50 isolating production zone 30 from injection
zone 32.
Formation fluid 16 enters wellbore 28 at production zone 30 and enters the
downhole oil-water
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system 10 at inlet 40 of pump 36 from which it is pumped into first stage
(e.g., bulk) separator
12. First stage separator 12 separates a first production stream 18 (e.g., oil
stream) and a first
injection stream 17 (e.g., water stream) which pass into flow manifold 42 via
a dual conduits 56
for example. First production stream 18 is routed at flow manifold 42 to the
surface through
conduit 46 as output production stream 20. Flow manifold 42 routes first
injection stream 17
into second stage separator 14 (e.g., deoiler) which separates first injection
stream 17 into an
output injection stream 19 and a second production stream (e.g., oil stream).
The oil stream from
second stage separator 14 is directed uphole to surface 34 via tubular 46 as
output production
stream 20. The output injection stream 19 continues downhole in the depicted
embodiment
through conduit 44 through packer 50 where it is injected into injection
formation 32.
[00341 Figure 4 is a schematic of a downhole oil-water separation system 10
according to one or
more aspects of the present disclosure disposed in a well wherein production
zone 30 is located
below injection zone 32. In this embodiment inlet 40 is disposed in an
internal chamber 57 (e.g.,
bore) of a housing 58. In the depicted embodiment, pump 36 and first stage
separator 12 are also
disposed inside of housing 58. Chamber 57 of housing 58 is in fluid
communication with
production zone 30 through packer 50. Injection zone 32 is isolated from inlet
40 via housing 58
and isolated from production zone 30 via packer 50.
100351 Production fluid 16 enters wellbore 28 and passes into housing 58 where
it enters the
downhole separation process flow path at inlet 40 of pump 36 in this
embodiment. First stage
separator 12 separates total inlet stream 16 into a first injection stream 17
and a first production
stream 18. The water and oil stream may be passed from first stage separator
12 through dual
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conduit 56 for example to a flow manifold 60. First production stream 18 is
routed to surface 34
via tubular 46. First injection stream 17 is directed to second stage
separator 14 where it is
separated into output injection stream 19 and second production stream 22 (see
Figure 1). The
second production stream (e.g., oil stream) off of second stage separator 14
is pumped to the
surface via flow manifold 42 and tubular 46 for example. Second injection
stream 19 is routed
through flow manifold 42, in the depicted embodiment, and discharged into
welibore 28 (e.g.,
casing 52) and injected into zone 32 of the formation.
[0036] The foregoing outlines features of several embodiments so that those
skilled in the art
may better understand the aspects of the present disclosure. Those skilled in
the art should
appreciate that they may readily use the present disclosure as a basis for
designing or modifying
other processes and structures for carrying out the same purposes and/or
achieving the same
advantages of the embodiments introduced herein. Those skilled in the art
should also realize
that such equivalent constructions do not depart from the spirit and scope of
the present
disclosure, and that they may make various changes, substitutions and
alterations herein without
departing from the spirit and scope of the present disclosure. The scope of
the invention should
be determined only by the language of the claims that follow. The term
"comprising" within the
claims is intended to mean "including at least" such that the recited listing
of elements in a claim
are an open group. The terms "a," "an" and other singular terms are intended
to include the
plural forms thereof unless specifically excluded.
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