Note: Descriptions are shown in the official language in which they were submitted.
CA 02775841 2015-09-18
DOWNHOLE GAS AND LIQUID SEPARATION
Background
The present invention relates to the separation of gas from liquids in oil and
gas
wells, and particularly to methods of downhole separation of gas and liquid
from a
producing reservoir.
Production fluid, the fluid obtained from oil and gas wells, is generally a
combination of substantially incompressible liquids and compressible gases. In
particular, production fluid for methane production from coal formations
includes such
gases and water. Conventionally, pumping of such production fluid has
presented
difficulties due to the compressibility of the gases, which leads in the best
of
1 0 circumstances to reduction in pumping efficiency, and more detrimental,
to pump
lockage or cavitation.
Cavitation happens as cavities or bubbles form in pumped fluid, occurring at
the
low pressure or suction side of a pump. The bubbles collapse when passing to
higher
pressure regions, causing noise and vibration, leading to material erosion of
the pump
components. This can be expected to cause loss of pumping capacity and
reduction in
head pressure, reducing pump efficiency to the point of, over time, pump
stoppage.
This has lead to the use of downhole gas and liquid separators to remove much
of the compressible gasses from the production fluid prior to admission of the
liquid
component of the production fluid to the pump suction port. Gas separation
conventionally is performed on production fluid at the bottom of the tubing
string before
pumping the liquid up the tubing, thereby improving efficiency and reliability
of the
pumping process. In some cases, waste components of the production fluid are
re-
injected above or below the production formation instead of bringing such
waste
components to the surface.
Examples of prior art downhole gas and liquid separators are taught by U.S.
5,673,752 to Scudder et al. (a separator that uses hydrophobic membrane for
separation);
U.S. 6,036,749 to Ribeiro et al. (a helical separator); U.S. 6,382,317 to Cobb
(a powered
rotary separator); U.S. 6,066,193 to Lee (inline separators with differently
sized internal
diameters); U.S. 6,155,345 to Lee et al. (a separator having flow-through
bearings and
multiple separation chambers); U.S. 6,761,215 to Morrison et al. (a rotary
separator with
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a restrictor that creates a pressure drop as the fluid passes to the
separation chamber);
and U.S. 7,461,692 to Wang (multiple separation stages with each separation
stage
having a rotor with an inducer and impeller).
While many improvements have been taught by the prior art, there remains the
need for efficient downhole gas separation that addresses the problems and
shortcomings of such art, as the demands of the hostile environment of the
downhole
conditions of reservoir fluid at advanced pressures and elevated temperature
conditions
have continually been challenging. There is a need for downhole gas separation
that can
provide improved production rates while maintaining improved fluid lifting
efficiencies
over widely variable production conditions. It is to these improvements that
the
embodiments of the present invention are directed.
Summary of the Invention
Various embodiments of the present invention are generally directed to the
production of gas and liquid from a subterranean formation.
In accordance with some embodiments, a method is provided for separating gas
from liquid in a gas and liquid producing oil well having a bore extending
from ground
surface to a reservoir level and having a tubing string extending from the
surface. The
method includes separating gas from liquid by a downhole gas separator having
a
separation chamber; and pumping liquid from the separation chamber by a
downhole
submersible pump to the tubing at a rate to at least partially vacate the
separation
chamber whereby sufficient space is provided in the separation chamber for the
gas to
separate from the liquid, the liquid passing to the tubing and the gas passing
to the well
bore.
In accordance with other embodiments, a method is provided for use in a gas
and
liquid producing well in which tubing extends in a well bore from ground
surface to a
reservoir fluid level. The method includes separating gas from liquid in a
downhole gas
separation chamber, and pumping liquid from the separation chamber at a rate
to
maintain a less than full liquid level in the separation chamber to provide
sufficient
3 0 space in the separation chamber for gas to have sufficient residence
time to substantially
separate from the liquid, the liquid passing to the tubing and the gas passing
to the well
bore.
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2a
In accordance with another embodiment there is provided a method of separating
gas from liquid in a fluid produced by a well having a bore extending from
ground
surface to a subterranean reservoir, the method comprising:
pumping the fluid at a first flow rate into a separation chamber; and
pumping liquid from the separation chamber at a second flow rate that is
greater
than the first flow rate to create a space in the separation chamber, at least
a portion of
the gas separating from the liquid and the separated gas passing through the
space to the
bore.
In accordance with another embodiment there is provided in a gas and liquid
producing oil well in which tubing extends in a well bore from ground surface
to a
reservoir, a method comprising separating gas from liquid in a downhole gas
separation
chamber by pumping liquid from the separation chamber at a rate to maintain a
less than
full liquid level in the separation chamber, the separation chamber being of
sufficient
length for gas to substantially separate from the liquid, the liquid passing
to the tubing
1 5 and the gas passing to the well bore.
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These and various other features and advantages that characterize the claimed
invention will become apparent from the following detailed description, the
associated
drawings and the appended claims.
Brief Description of the Drawings
Details of various embodiments of the present invention are described in
connection with the accompanying drawings that bear similar reference
numerals.
FIG. 1 is a partially detailed, side elevational representation of a downhole
gas
separator capable of practicing the present invention.
FIG. 2 is a partially detailed, side cut away, elevational view of one section
of the
downhole gas separator of FIG. 1.
FIG. 3 is a full cutaway elevational view of a separator section of the
downhole
gas separator of FIG. 1.
FIG. 4 is a partially cut away view of a back pressure diffuser of a pumping
stage
of the separator section of FIG. 3.
FIG. 5 is a partially cut away view of an impeller of a pumping stage of FIG.
3.
FIG. 6 is a partially cut away view of the back pressure device of the
separator
section of FIG. 3.
FIG. 7 is a side cut away view of a separator section of the separator of FIG.
1
with an alternative internal pump and vortex generator.
FIG. 8 is a functional block representation of a gas and liquid producing well
configured and operated in accordance with various embodiments.
FIG. 9 shows a graphical representation of an exemplary pump curve that can be
used to configure the well of FIG. 8.
FIG. 10 is a schematic representation of a two-stage separator of the
equipment
configuration depicted in FIG. 8.
FIG. 11 is a plan view of a back pressure device in the form of a plate having
a
plurality of calibrated fluid passing bores.
Description
Describing the specific embodiments herein chosen for illustrating the present
invention, certain terminology is used that will be recognized as being
employed for
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4
convenience and having no limiting significance. For example, the terms "top",
"bottom", "up" and "down" will refer to the illustrated embodiment in its
normal
position of use. "Inward" and "outward" refer to radially inward and radially
outward,
respectively, relative to the longitudinal axis of the illustrated embodiment
of the device.
"Upstream" and "downstream" refer to normal direction of fluid flow during
operation.
All such terminology shall also include derivatives thereof.
The present disclosure is generally directed to production fluids from a
subterranean formation, such as gas, water (fresh or brine), oil or any other
matter that
are generally collectively referred to herein as production fluid. As
explained below, a
method is generally disclosed for separating gas from liquid in a gas and
liquid
producing oil well having a bore extending from ground surface to a reservoir
level and
having an oil well tubing extending from the surface. Gas is separated from
liquid by a
downhole gas separator having a gas and liquid separation chamber, and liquid
is
pumped from the separation chamber by a variable speed downhole submersible
pump
1 5 to the oil well tubing at a rate to at least partially vacate the
separation chamber, thereby
providing sufficient space in the separation chamber for the gas to have
adequate
residence time in the chamber to separate from the liquid. Both the liquid
stream, which
passes to the tubing, and the separated gas stream, which passes external to
the tubing to
the well bore, flow as separated streams to the surface.
2 0 More particularly, the downhole gas separator receives gas and liquid
fluid from
the reservoir through the well bore, restricting the amount of gas and liquid
entering the
separation chamber to a predetermined flow rate that is less than the set
pumping rate of
the upstream submersible pump. A vortex of the gas and liquid is generated in
the
separation chamber so liquid is moved to the periphery of the separation
chamber and
2 5 the gas remains near the axial center of the separation chamber; the
gas is separated
from the liquid to pass through a gas outlet port into the well bore and
transported to the
surface by the buoyancy, and the separated liquid passes to a liquid inlet
port of the
submersible pump.
The rate of fluid flow to the separation chamber is selectively determined in
30 relation to the liquid pumping rate of the downhole submersible pump so
as to admit
less liquid to the separation chamber than the liquid pumping rate of the
downhole
submersible pump. That is, the capacity size of the downhole submersible pump
will be
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considered in sizing the inlet flow rate to the separation chamber, and the
pumping rate
will be set, so as to cause the submersible pump to run "lean", thereby
inducing a drop
in pressure in the separation chamber.
This selected sizing of components provides the capability for the submersible
5 pump to continuously "outrun" and empty liquid from the separation
chamber, and
generally, the submersible pump will run just on the edge of cavitation. This
is a new
and revolutionary theory of operation that is contrary to conventional systems
that seek
to maintain the liquid passing into the pump under compression to prevent such
cavitation, conventionally considered to be deleterious. The efficacy of the
present
embodiments has been successfully demonstrated in numerous field installations
having
performance unmatched by conventional systems.
In accordance with a preferred embodiment, the gas and liquid fluid received
by
the downhole gas separator is passed through a flow restrictor having one or
more
calibrated bores, the sum of the cross sectional flow areas of the calibrated
bores being a
predetermined value that permits passage of the gas and liquid fluid at a
predetermined
flow rate that is less, by a predetermined amount, than the pumping rate of
the
submersible pump.
While the various embodiments of the present invention are not limited to a
particular separator apparatus, the downhole separation will be described as
being
conducted by a downhole separator 10 shown in FIG. 1. As will become clear,
the
downhole separator 10, in its operational application, will be supported from
a
submersible pump (not shown in FIG. 1) that in turn is supported from the
lower end of
a tubing string (also not shown) that is positioned in the well bore of an oil
well that
provides fluid communication with a gas and oil producing geological,
underground
reservoir so the gas and oil fluid can be pumped to surface located
facilities. As used
herein, the term oil well shall have its usual meaning of an oil producing
well, a gas
producing well or a gas and oil producing well.
The downhole separator 10 preferably embodies a lower first separation section
12 and an upper second separation section 14. Each of the separation sections
12, 14 has
a housing defining an interior cavity in which, as described below, is located
a flow
restricting means, an internal pump and a separation chamber. Except as
described
herein, the construction of the first and second separation sections 12, 14 is
essentially
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6
the same, so it will be necessary only to describe the construction details
with regard to
one of the sections. Of course, it will be appreciated that the quantity of
production fluid
passing through the lower, first separation section 12 will be reduced by the
amount of
gas removed therefrom, so that the quantity of fluid passed to the upper,
second
separation section will be less than that through the first separation
section. Thus, the
sizing of the internal components will be different for the two separation
sections.
The number of separator sections, and the flow capacity of the sections, is
predetermined to be less than the pumping capacity of the submersible pump,
which in
turn is engineered to service the withdrawal capacity of the well. This is
also a function
of the gas content of the production fluid. The entering flow rate from the
reservoir
through the separator, being determined to be lower than the submersible pump
flow
rate, assures vacating the upper separation chamber. The downstream separator
sections
are designed to handle lower fluid flow rates, because the gas removed from
upstream
sections diminish the amount of fluid passed to the downstream separator
sections and
1 5 thereafter to the submersible pump.
As depicted in FIG. 1, the first separation section 12 has a housing 16, a
base 18,
and a head member 20, and the second separation section 14 also has a housing
16, a
base 18 and a head member 20. Each housing 16 is a hollow, elongated,
cylinder. The
base 18 of the lower section 12 has a plurality of circumferentially arranged
inlet ports
22 that communicate production fluid received from the underground reservoir
to the
interior cavities of the housings 16 of the first and second separator
sections 12, 14.
As shown in FIG. 2, a cutaway view of the upper or second separation section
14, the head member 20 has a body portion 24 that is generally cylindrically
shaped and
has a plurality of upwardly extending threaded studs 26. An external,
circumferential
channel 28 extends around the body portion 24, and the body portion is
externally
threaded to engage with internal threads at the upper end of the housing 16.
An
upwardly opening, tapered cavity 30 extends through the body portion 24.
An upper bearing 32 is mounted in the cavity 30, and a plurality of
circumferentially arranged liquid outlet ports 34 extend upwardly through the
body
portion 24 to communicate with the cavity 30. A plurality of circumferentially
arranged
gas outlet ports 36 extend upwardly and outwardly to the channel 28 to
communicate
with the casing.
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An elongated cylindrical drive shaft 38 with opposing splined ends extends
through an interior cavity 40 of the housing 16 and is supported by
appropriately spaced
apart bearings to extend the length of the housing 16. As conventionally
provided, a
downhole electric motor (not shown in these figures) is connected to, and
supported by,
the base 18 on the lower end of the first separator section; the drive shaft
38 connects to,
and is rotated by the downhole electric motor, which is powered by electrical
conductor
lines (not shown) that extend upwardly through the well bore to a power source
at the
ground surface. The upper end of the drive shaft 38 is connected to, and
serves to power,
the submersible pump.
1 0 A pair of vortex generators 42 are provided in the interior cavity 40,
with each
vortex generator having a plurality of spaced vertical paddles 44 extending
radially from
a hub member 46 that is supported by the drive shaft 38. Each of the vortex
generators
42 is disposed within a separation chamber portion 48. As the drive shaft 38
is rotated,
typically at 3500 rpm, the paddles 44 stir the passing fluid in the separation
chamber 48
1 5 into a vortex, with the liquid forced against the inner surface of the
housing 16,
separating the gas to pass along the axial center thereof.
The dimensional length of the separation chamber 48 is determined so as to
provide sufficient fluid dwell time (the time for fluid to travel the length
of the chamber)
to effect separation of gas from the production fluid. As depicted in FIGS. 2-
3, the
2 0 length of the separation section 14 in which components below the
separation chamber
48 is designated as Li and the length of the separation chamber portion 48 of
the
separation chamber is designated as L2. Typically, the length L2 will be about
twice the
length Ll, or greater. While not limiting, a typical length Ll will be about 2
feet, and a
typical length of L2 will be about 2 1/2 to 5 feet. While the length of the
separation
25 chamber is not critical, it is important to establish sufficient length
such that gas
separation occurs as the fluid passes there through. In practice, it has been
found that the
length of the separation chamber for a downhole separator, such as the
separator 10,
requires approximately 1 to 10 inches per 100,000 cubic feet of gas (or 0.1
MCF), and
depending on the production pressure, usually requires a minimum of about 12
inches.
30 Gas is separated from liquid by the downhole gas separator 10 in the
separation
chamber 48, and liquid is drawn from the separation chamber 48 by the
submersible
pump (not shown) and to the tubing string at a rate to partially vacate the
separation
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8
chamber; as used herein, the term partially vacate is meant to convey that the
separation
chamber 48 will have a dynamic low liquid level maintained therein during
proper
operation, and space is thereby provided for gas and liquid separation. As
noted, the
length L2 of the separation chamber 48 can vary, but this length is
established as
necessary to provide sufficient space and time for the gas to effectively
separate from the
liquid. The separated gas is passed to the casing through the gas outlet ports
36 while the
remaining fluid (mostly liquid) is passed to an inlet port of the submersible
pump via the
liquid outlet ports (not shown) 34 to be pumped through the tubing string.
As will be discussed further herein below, the downhole gas separator 10
receives gas and liquid fluid from the underground geological reservoir
through the well
bore, and restricts the amount of gas and liquid entering the separation
chamber 48 to a
flow rate less than the pumping rate of the submersible pump. A vortex of the
gas and
liquid is generated in the separation chamber by rotation of the vortex
generator 42 so
liquid is moved to the periphery of the housing 16 and the gas remains passing
near the
1 5 axial center thereof, the gas being separated from the liquid to pass
through gas outlet
ports 36 into the well bore and the separated liquid passes out liquid outlet
ports 34 to
the inlet port of the submersible pump.
Further details of the construction will now be undertaken with reference to
FIG.
3. The second separation section 12 includes an internal pump 50 with first
and second
pumping stages 52 and 54, a first sleeve 56, a means for restricting flow 58,
and a
second sleeve 60, with each having a cylindrical exterior sized and shaped to
fit into the
interior cavity 40 of the housing 16, and with each being assembled into the
interior
cavity 40 in the above listed order from the base 18 to the head member 20. In
the
illustrated embodiment the means for restricting fluid flow 58 is a back
pressure device
2 5 62, also sometimes referred to herein as the fluid flow restrictor 62;
and it will be
understood that other means for restricting fluid flow are suitable for the
present
invention.
The first and second pumping stages 52 and 54 each include an impeller housing
64 and a back pressure diffuser 66, sized and shaped to fit into the interior
cavity 40 of
the housing 16, and an impeller member 68. Internally disposed cylinder
spacers (not
separately numbered) serve to support and separate the components disposed in
the
internal cavity of the housing 16.
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9
As shown in FIG. 4, the back pressure diffuser 66 includes a bore 70 extending
upwardly through the center of back pressure diffuser 66, a cylindrical outer
wall 72, and
a plurality of spaced, radially arranged, upwardly, inwardly and helically
extending
passages 74 between the bore 70 and the outer wall 72, with the passages 74
being
separated by radial fins 76. Referring again to FIG. 3, the impeller housing
64 and back
pressure diffuser 66 define an impeller cavity 78. FIG. 5 shows the impeller
68 having a
hub 80 and a plurality of spaced, radially arranged, upwardly, outwardly and
helically
extending passages 82 around the hub 80.
The back pressure device 62, as shown in FIG. 6, is generally cylindrical with
an
1 0 intermediate bearing aperture 84 and a plurality of spaced, radially
arranged passages 85
extending through the back pressure device 62. An intermediate bearing 86 is
mounted
in the intermediate bearing aperture 84. Passages 85 are configured to
restrict fluid flow
so that back pressure device 62 divides the interior cavity 40 into an
upstream, first
chamber 88 and the separation chamber 48. In the illustrated embodiment the
passages
1 5 85 extend upwardly, inwardly and helically, so that the passages 85
initiate vortex
generation in the production fluid as the production fluid flows into the
separation
chamber 48.
The elongated drive shaft 38 extends through the interior cavity 40 of both
the
first and second separator sections 12 and 14 for rotation by an electrical
pump (not
20 shown) supported by the base 18 of the lower or first separation section
12. Bearing
journals are spaced along both first and second separator sections 12, 14 to
support the
shaft 38 for rotary motion; and the impellers 68 are mounted on the shaft 38
and keyed
for rotation therewith. The vortex generator 42 is depicted as a paddle
assembly
positioned in the separation chamber 48 with the hub member 46 supported by
the drive
25 shaft 38 and having the plurality paddles 44 extending radially from the
hub member 46.
Other styles of vortex generator, such as spiral or propeller, are also
suitable. The
separator chamber 48 is elongated, having sufficient length to allow
sufficient time for
gas to separate from the liquid in the production fluid. In practice, the
length of the
separator chamber can be up to three feet or longer.
3 0 By way of example, and not as a limitation, the back pressure device 62
can be a
bearing housing of the type normally used to stabilize a long shaft in a well
pump. Such
CA 02775841 2015-09-18
bearing housings are available in different capacities to compliment the
capacity of the
well pump. The back pressure device 62 has a selected capacity that is
selected such that
the flow rate of liquid passing to the inlet port of the submersible pump is
less than the
capacity of the submersible pump. That is, the object is to operate the
submersible
5 pump, coupled to the downhole separator 10, somewhat lean or starved,
that is, running
lean of its full fluid pumping capacity at the operating rotation as powered
by the drive
shaft 38. Thus, the selected capacity of the back pressure device 62 is limits
fluid flow.
Referring back to FIG. 3, each of the first and second sleeves 56 and 60 is a
relatively
thin walled hollow cylinder. The first sleeve 56 spaces the back pressure
device 62 from
1 0 the pump 50. The second sleeve 60 spaces the back pressure device 62
from the head
member 20.
In accordance with a preferred embodiment, the gas and liquid received by the
downhole gas separator is passed through a flow restrictor with calibrated
holes or bores
the size of which permit passage of production fluids at a predetermined flow
rate. And
1 5 as discussed, the predetermined flow rate serves to determine the rate
of separated liquid
that is passed to the submersible pump. That is, the calibrated bores are
sized to permit
fluid flow of oil and gas, that will be of a different size in a well making
1000 BPD
(barrels of liquid per day) and 80% gas than in a well making 1000 BPD and 40%
gas.
The calibrated bores are predetermined to permit passage of the correct amount
of fluid
2 0 to pump the well down with whatever percentage of gas that enters the
separator to
supply the correct amount of fluid flow for the well.
For alternative embodiments, each of the first and second separator sections
can
have a drive shaft extending therethrough to drive the components, and these
individual
drive shafts can be connected by means of a coupler (not shown) so an electric
motor
2 5 (not shown) connected to the lower end of the drive shaft in the first
separator section
will drive both of the drive shafts. Also, the upper end of the drive shaft
extending from
the upper or second separation section 14 can be connected by a similar
coupler (not
shown) to the drive shaft of a submersible pump.
The studs 26 on the head member 20 of the first separation section 12 connect
to
30 a flange on the base 18 of the second separation section 14 to
interconnect the first and
second separator sections. As mentioned above, a typical installation of the
separator 10
mounts between a motor on the base 18 of the first separation section 12 and a
well
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11
pump secured to the head member 20 of the second separation section 14. The
impeller
68 of the second pumping stage 52 of the first separation section 12 receives
the
pressurized production fluid from the first pumping stage 54 and further
increases the
pressure of the production fluid. The back pressure diffuser 66 of the second
pumping
stage 54 of the second separation section 14 builds further fluid pressure,
forcing the
production fluid into the first chamber 88 of the second separation section
14.
In other words, the first impeller 68 starts fluid going up and the size of
the bores
in the back pressure diffusers 66 is what determines the fluid flow produced
and
pressure required to produce the desired flow rate through the calibrated
bores. The back
1 0 pressure diffuser 66 also maintains the pressure till the next impeller
68 can pick up the
fluid flow and maintain the flow while increasing the pressure on the fluid.
This above
described process is also what occurs in the lower or first separation section
12 with this
exception; as the gas is separated from the production fluid in the lower or
first
separation section 12, the separated portion of gas is exhausted from the gas
outlet port
1 5 36 of the head member 20 into the well bore casing external to the
tubing string, while
the remaining portion of the fluid exiting the separation chamber 48 of the
lower or first
separation section 12 passes through the upper cavity 30 of the head member 20
to the
lower end of the connected upper or second separation section 14.
The process is repeated in the second separation section 14. The impellers 68
of
20 the first and second pumping stages 52 and 54 of the second separation
section 14 pulls
the remainder production fluid (the amount of production fluid to the first
separation
section 12 and lessened by separation and exhaustion of gas from the first
separation
section 12) and increases the velocity of the fluid. The back pressure
diffuser 66 of the
first and second pumping stages 52, 54 of the second separation section 14 the
25 pressurized remainder production fluid, forcing the remainder production
fluid into the
first chamber 88 of the second separator section 12. As gas is separated from
the
remainder production fluid in the upper or second separation section 14, the
gas is
exhausted from the gas outlet port 36 of the head member 20 into the well bore
casing
external to the tubing string. The liquid of the remainder production fluid is
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passed from the separation chamber 48 of the second separation section 14
through the
upper cavity 30 of the head member 20 to the inlet port of the submersible
pump.
Returning to FIG. 6, which shows of the back pressure device 62, the passages
85 limit the flow of production fluid through the back pressure device 62
between the
first chamber 88 and the separation chamber 48. From the back pressure device
62 the
liquid and gas travel upward to the separation chamber 48 and contact with the
vortex
generator 42. As the drive shaft is rotated by an electric motor, typically at
about 3500
rpm (but the rpm can be more or less as required for a particular
installation), the
paddles 44 whirl the liquid and gas in a circular vortex, thereby
centrifugally separating
the liquid at radially outward and the gas nearest to the axial center of the
separation
chamber 48. The liquid passes upwardly to the liquid outlet ports 34. Gas
passes
upwardly to the gas outlet ports 36 and out the downhole separator 10 into the
well
annulus external to the tubing string. The second separation section 14
separates gas
remaining in the production fluid by the same process, and the production
fluid flows
from the second separation section 14 into the well pump.
The capacity of the separator 10 is selected based on the required pumping
rate
and the gas content of the production fluid. The capacity of the separator 10
is
determined by the capacity of the first and second separation stages 12 and
14. The
capacity of each of the first and second separation stages 12 and 14 is
determined by the
2 0 size and number of pumping stages and the restriction of the back
pressure device.
Although two pumping stages are shown for each of the first and second
separation stages 12 and 14, additional pumping stages can be added as may be
required
to increase pressure on the production fluid as required to effect proper
separation. That
is, the number of stages is determined as that which is necessary to effect
more pressure
2 5 increase of the passing production fluid. For example, the pressure
increase might be 13
psig for one stage and an accumulative 65 psig for five stages.
It will be appreciated that the capacity of each of the first and second
separation
stages 12 and 14 will be predetermined selected separately, as a portion of
the gas in the
production fluid is removed and exhausted to the well annulus, the liquid
passing to the
30 second separation section 14 will be the same as that entering the first
separation section
12; of course, the total amount of production fluid entering the second
separation section
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13
14 will be less by the amount of gas separated and removed from the first
separation
section 12. The capacity of each of the separator sections will generally be
determined
by selecting an appropriately sized fluid restrictor, or back pressure device
62. The
number and capacity of the pumping stages in each separator section is
selected to build
up pressure in its separation chambers 48.
The capacity of the back pressure devices 62 in each separator section is
selected
to limit the fluid flow to the separation chambers 48 to assure that the
separation
chambers 48 will not fill as fluid is withdrawn. The fluid flow out of each
separation
chamber 48 is the gas exiting through the gas outlet ports, and the fluid is
pulled from
the separation chambers through the liquid outlet ports by the next downstream
pump,
whether that pump is in the next separator section or that pump is the
submersible well
pump.
As a working, typical field example, a well might be required to pump 1500
BPD (barrels per day) where the production fluid is a mixture of oil and gas,
so the
submersible pump would be designed by the oil well operator to have a capacity
of 1600
BPD so that the pump will maintain sufficient dynamic vacation of the
separation
chamber of the upper separator section. For this example case, the first and
second
separator sections 12 and 14 can each include five pumping stages with a
capacity of
6000 BPD each, the back pressure device 62 for the first separation section 12
could
2 0 have a capacity of 3000 BPD and the back pressure device 62 for the
second separation
section 14 could have a capacity of 1500 BPD.
A method of separating gas and liquid from production fluid in a well,
embodying features of the present invention, includes providing connected
first and
second separator sections each having a first chamber and a separation
chamber,
2 5 pumping production fluid into the first chamber of the first separator
section, limiting
flow of production fluid into the separation chamber of the first separator
section,
increasing the pressure of the production fluid as the fluid passes between
the first and
second chamber of the first separator section, generating a vortex in the
separation
chamber of the first separator section, pumping production fluid from the
separation
3 0 chamber of the first separator section into the first chamber of the
second separator
section, limiting flow of production fluid into the separation chamber of the
second
CA 02775841 2015-09-18
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separator section, and generating a vortex in the separation chamber of the
second
separator section.
The gas is passed from each separation chamber through gas outlet ports to the
well bore annulus external to the tubing string. The liquid passes from the
separation
chamber through liquid outlet ports to the second separation section. The
steps of the
first separation section are repeated in the second separation section wherein
the liquid
separated in the separation chamber passes to the inlet port of a submersible
pump. The
fluid flow capacity of the last separation section is coordinated with the
capacity of the
submersible pump to be less than the capacity of the submersible pump so that
the last
separation chamber is dynamically vacated by the submersible pump to provide
sufficient space for the separation of gas and liquid.
Turing now to FIG. 7, shown therein is the first or lower separation section
12
with alternative construction features capable of practicing the present
inventive method.
FIG. 7 shows the first separation section 12 with an alternative internal pump
100 and an
alternative vortex generator 102. The internal pump 100 is an inducer 104
having an
elongated, cylindrical hub member 106 and a pair of opposed blades 108 that
project
radially from hub member 106 in an augur shape. The hub member 106 is mounted
on
drive shaft 38 and secured on drive shaft 38 by key 85, so that the inducer
104 rotates
with shaft 38. The length of inducer 104, the number of blades 108 and the
angle of the
2 0 blades 108 can vary. The vortex generator 102 includes a pair of spaced
paddle
assemblies 110, each having a hub member 112 mounted on drive shaft 38, and a
plurality of spaced vertical paddles 114 that extend radially from the hub
member 112.
The second or upper separation section 14 is preferably constructed
identically to that
described for the first separation section 12 with the exception of the inlet
ports 22 for
entry of the production fluid to the first separation section 12, as discussed
above.
The inducer 104 in first separation section 12 pumps production fluid through
the first chamber 88 to the back pressure device 62, restricting the fluid
flow to the
separation chamber 48. The paddles 114 stir the liquid and gas into a circular
vortex,
thereby centrifugally separating the liquid to the radial outside and the gas
to the axial
center of the separation chamber 48. The remainder production fluid passes
upwardly to
the liquid outlet ports 34 and to the second separation section 14. Gas passes
upwardly
to the gas outlet ports 36 to the well annulus external to the tubing string.
The second
CA 02775841 2015-09-18
separation section 14 separates the gas of the remainder production fluid by
the same
process, and the liquid of the remainder production fluid flows from the
second
separation section 14 to the submersible pump.
It will be appreciated that the various system parameters of the disclosed
system
5 will vary greatly depending on the requirements of a given well. If the
parameters are
not correctly set, then the efficacy, and indeed the operational benefit of
the separator,
can be diminished or eliminated entirely. Moreover, the production rates of
the well in
terms of the amounts of oil and gas extracted from the well may be
significantly reduced
over what can be achieved using the presently preferred embodiments.
1 0 As noted above, known prior art systems seek to employ a liquid-gas
separator to
prevent gas lock, or cavitation, of the submersible pump, which can lead its
damage or
stalling, so that ultimately the need to remove and reinsert the submersible
pump to
restart the process. The previously attempted solutions seek to maintain
sufficient
volume and pressure of the inlet liquid to the pump so that, to the extent
that any gas is
1 5 present in the liquid as the liquid passes into the submersible pump,
the gas remains
under compression as relatively small bubbles that do not interfere with the
ability of the
submersible pump to force the liquid component of the subterranean fluid to
the surface.
Previous systems thus accept the fact that the pumped fluid will maintain a
substantial
amount of compressed gas therein.
2 0 FIG. 8 is a functional block representation of an exemplary well system
200
configured and operated in accordance with various embodiments. The system 200
includes a well bore 202 that extends downwardly to a subterranean formation
204
having a mixture of liquid and gas. The liquid may comprise an admixture of
water
(fresh or brine) and oil or other liquid hydrocarbons, and the gas may
comprise methane
or other pressurized gases. The purpose of the well system 200 is to
ultimately extract
commercially useful components from the subterranean formation, such as
natural gas
and oil.
The well bore 202 will be of the depth suitable to reach the subterranean
formation 204; such can be several hundreds or thousands of feet, and may be
encased in
3 0 a cylindrical casing (not separately illustrated). A liquid level
within the bore is
generally represented at 206, with area 208 representing a pressurized vapor
space above
this level. A tubing or pump string 210 extends down the center of the well
bore into and
below the liquid level 206 useful in urging the upward production of the
desired
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16
subterranean components. The exemplary pump string 210 includes the
aforementioned
motor (M), liquid-gas separator (S), and submersible pump (P), respectively
numerically
denoted as 212, 214 and 216.
The pump string 210 further includes a liquid conduit or tubing 218 along
which
the pumped liquid passes upwardly through the vapor space 208 to a water-oil
separator
(WOS) 220, which extracts the water to produce a flow of oil for a downstream
piping
or storage network. A well cap mechanism 222 retains the pressure on the
pressurized
vapor space 208 and directs the gaseous components to a water-gas separator
(WGS) to
similarly direct a flow stream of pressurized natural gas for downstream
processing. It
will be appreciated that the diagram of FIG. 8 is greatly simplified and any
number of
additional components such as chokes, valves, instrumentation, conduits,
conductors,
and other elements may be incorporated in the system 200.
To configure the system 200, the following steps may be carried out in
accordance with various embodiments. First, the desired liquid production rate
of the
well is identified in terms of the amount of liquid to be pumped from the
well. This may
be expressed in any convenient form, such as the conventionally well utilized
production
rate of barrels per day (BPD), with each barrel constituting a volume of
liquid equal to
42 gallons and a day constituting 24 hours. For purposes of the present
example, a liquid
production rate value of 4,000 BPD will be selected.
At this point it will be recognized that a number such as 4,000 BPD does not
usually mean that 4,000 barrels of oil will be produced each day. Rather, the
amount of
oil will tend to be significantly less than this amount, because in most
exemplary
environments the liquid will largely be water (or other non-oil liquids) and a
lesser
component of the extracted liquid will be oil. The amount of oil within the
liquid as a
percentage can be from as low of around 1% to upwards of 10% or more. Oil and
water
do not mix, and oil generally tends to have a lower specific gravity than
water. A
measure of the specific gravity of the subterranean fluid can give some
indication of this
ratio. It is known that salt water has a specific gravity (Sg) of around 1.05,
so a Sg near
this value will generally tend to indicate a relatively low oil content. A
lower Sg, such as
a value of around 0.8, can indicate a relatively larger oil content. Such
values can be
obtained from conventional instrumentation methods and are employed as set
forth
below.
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17
Another initial value that may be obtained during the configuration of the
system
200 is the ratio of gas to liquid to be produced by the well. It is known in
the art that
these ratios can vary widely from formation to formation, and can vary widely
over the
production age of a formation. It will be appreciated that the liquid-gas
separator system
disclosed herein is effectual for environments where there is a substantial
amount of gas
within the well bore; clearly, if the well is substantially depleted of
gaseous pressure, a
pump jack or other mechanical lifting means may be required to lift the liquid
to the
surface and there is no need for liquid-gas separation.
The amount of gas to be produced can be estimated using various well known
1 0 means and instrumentation, and is usually expressed in terms of
thousands of cubic feet
(MCF). This can be conveniently converted to equivalent BPD volumetric rate
using
known conversion factors. For a present example, it will be conveniently
estimated that
the well system 200 of FIG. 8 will produce the equivalent of 2000 BPD of
natural gas.
Thus, the entire fluidic production rate (on average) will be about 6,000 BPD,
of which
4,000 (or roughly 67%) will be liquid. Assuming 10% oil, the well will thus
produce
about 400 barrels of crude oil per day.
The sequence in designing the system 200 generally involves steps of (1)
sizing
the submersible pump 216 to accommodate the desired liquid extraction rate of
4,000
BPD; and (2) sizing the liquid-gas separator 218 to accommodate the gas flow
rate of
2,000 BPD while ensuring the pump is enabled to meet the desired flow rate of
4,000
BPD.
To do this, the next piece of information that may be required is the depth of
the
liquid level line 206 relative to the surface. As before, this can be
determined using
suitable instrumentation. For purposes of the present example, a depth of
about 2,000
2 5 feet will be used. This means that the submersible pump 216 will need
to be sized to
pump the liquid a vertical height of about 2,000 feet.
FIG. 9 shows an exemplary pump curve 230 for a pumping stage such as
described previously herein. Since different pump styles and pump
manufacturers will
have different pump curve characteristics, curve 230 is exemplary and not
limiting. It is
3 0 contemplated that the curve 230 describes the characteristics for a
stage having two
floating impellers that rotate responsive to a keyed shaft passing there
through. The
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curve 230 is plotted against an x-axis 232 in terms of BPD and a y-axis 234 in
terms of
vertical height.
Point 236 on the curve shows that for a desired flow rate of 300 BPD of liquid
(at a specified Sg such as 1.05), each stage can pump this liquid a total of
20 feet. It
follows that the pump or tubing string 218 may be configured of 100 such
stages (100
stages x 20 feet/stage = 2,000 feet). This represents the general size and
capacity of the
pump; additional stages may be added or removed depending on empirical factors
or a
priori knowledge.
Next, a schematic representation of the two-stage separator 214 is shown in
FIG.
10, with upper and lower sections 240, 242. The liquid-gas separator 214 is
sized for this
pump configuration. This is carried out as discussed above to facilitate
sufficient flow
into the pump so that the submersible pump continuously empties the amount of
liquid
that is presented thereto from the uppermost separation chamber. It will be
recalled that
in presently preferred embodiments the separator includes two stages, a lower
stage and
an upper stage. The lower section 240 includes impellers 244, 246, back
pressure plate
248 and impeller or vortex generator 250. The upper section 242 includes
impellers 254,
256, back pressure plate 258 and impeller or vortex generator 260. The back
pressure
plates 248, 258 may take the form of a back pressure diffuser or a bearing
housing
support as discussed above, or a plate 262 with apertures or bores 264
extending there
through as shown in FIG. 11.
The lower or first back pressure plate 248 should be sized to accommodate the
entire inlet flow of fluid expected to pass there through, namely 6,000
equivalent BPD.
While not required, it will be contemplated that the impellers 244, 246 and
254, 256 will
form pumping stages that are nominally identical to the pumping stages used to
form the
pump 214. Hence, with reference again to the pump curve 230 in FIG. 9, it will
be
determined that the pumping of 6,000 BPD provides an equivalent vertical
height of
about 15 feet, as indicated by point 266. This vertical height can be
converted to an
equivalent pressure value by dividing the pressure by a well known conversion
factor of
2.31. In other words, the lower stage 240 of the separator 214 will generate
about
15/2.31 = 6.5 psig of pressure pumping the equivalent of 6,000 BPD against the
first,
lower back pressure plate 248.
The plate 248 is accordingly sized to accommodate the flow of 6,000 BPD at
this
pressure. The plate may be provisioned with a plurality of annular apertures
having a
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combined cross-sectional area sufficient to allow this much volume to pass
there
through. The total cross-sectional area may be empirically determined; it has
been
found, for example, that a cross sectional area of 5 square millimeters (mm2)
will permit
passage of about 500 BPD under certain operational conditions. Thus, a
suitable
combined equivalent area to allow 6,000 BPD to pass through the lower plate
248 may
be about 60 mm2. This is merely exemplary, however; empirical analysis may be
required to arrive at the particular value for a particular application.
Having sized the lower plate 248, the next determination to be made is an
evaluation of what percentage of gas will be removed by the lower stage 240.
Again, this
may require some empirical analysis. Generally, it has been found that the
amount of gas
in the liquid that passes from the lower stage 240 to the upper stage 242 will
depend on
a variety of factors including the specific gravity of the fluid. For a higher
Sg, less gas
may be removed whereas for a lower Sg, more gas may be removed. An exemplary
value may be 50% of the gas in the fluid passing into the lower stage 240 is
removed by
1 5 the lower stage. Using this value, it can be seen that there will now
only be the
equivalent of 1000 BPD (2,000 BPD x 0.50) of gas passing into the upper stage
242.
This means that, generally, the upper stage 242 will be receiving the
equivalent of about
5,000 BPD of fluid.
Returning again to the curve 230 of FIG. 9, a BPD rate of 5,000 BPD will
provide a vertical height value of about 18 feet, as indicated by point 268 on
the curve.
This converts to a back pressure of about 7.8 psig. The upper back plate 258
is sized to
permit the flow of the equivalent of about 5,000 BPD there through at this
pressure.
Empirical analysis will allow determination of this value. An exemplary value
may be
on the order of about 50 mm2 of total surface area of the apertures passing
through the
upper plate 242.
In some embodiments, the upper plate can be sized as a derated value of the
lower plate, rather than by making reference to the pump curve. The upper
plate will
generally tend to have a smaller cross-sectional area because of the removal
of gas from
the inlet fluid. Accordingly, the upper plate is sized to ensure that the
upper chamber is
3 0 supplied with just this amount so that the submersible pump empties the
separation
chamber and runs lean. This promotes the efficacy of the separator so that
substantially
no component of gas remains in the liquid stream passing through the pump.
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Once installed, in some embodiments the system can be adaptively adjusted to
attain an optimum level of performance through the adjustment of various
parameters.
This allows the system to be tuned to ensure that the upper chamber of the
liquid-gas
separator is being fully vacated by the pump operation; that is, the pump is
operated to
5 empty the upper chamber at the same rate at which the liquid is being
introduced into the
upper chamber.
Some systems utilize a variable frequency drive mechanism at the surface of
the
well that allows adjustments in the rotational rate of the motor that drives
the central
shaft to which the submersible pump, impellers and inducers are coupled. While
the
10 system may be designed to operate at a selected alternating current (AC)
frequency, such
as 60 Hz, an operative range may be available so that the motor can be rotated
at any
desired frequency from a lower rate of from around 50 Hz or less to an upper
rate of
around 70 Hz or more.
In such case, the system can be initially operated at a baseline frequency,
such as
15 60 Hz. The pump efficiency can be evaluated at this level through
various
measurements such as the volume of liquid passing to the surface, the pressure
of this
liquid, a pressure measurement within the upper chamber, and so on. If less
than
optimum pump efficiency is observed, a user can slowly increase the frequency
of the
motor operation, such as from 60 Hz to 65 Hz. This may result in an increase
in the
20 volume of liquid reaching the surface since the pump will generally be
able to pump
more liquid at a higher rotational rate, whereas the maximum amount of liquid
that can
flow into the upper chamber remains fixed due to the orifice size of the back
pressure
plate.
As the user continues to increase the frequency, there may be a point at which
higher frequencies do not provide further increases in the amount of liquid
being
pumped to the surface; that is, the volume of liquid becomes substantially
constant, but
the pressure of the fluid increases. The user may thus reduce the frequency of
the motor
back down to the point at which the maximum liquid volume, and the lowest
liquid
pressure, are obtained. Similar adjustments may be made to reduce the
frequency from a
first baseline frequency, such as 60 Hz, to a lower optimum frequency, such as
55 Hz.
Such adjustments may further be made from time to time (e.g., on a monthly
basis, etc.)
as formation conditions change to maintain the system operation at optimum
levels.
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21
The various features and alternative details of construction of the
apparatuses
described herein for the practice of the present invention will readily occur
to the skilled
artisan in view of the foregoing discussion, and it is to be understood that
even though
numerous characteristics and advantages of various embodiments of the present
invention have been set forth in the foregoing description, together with
details of the
structure and function of various embodiments of the invention, this detailed
description
is illustrative only, and changes may be made in detail, especially in matters
of structure
and arrangements of parts within the principles of the present invention to
the full extent
indicated by the broad general meaning of the terms in which the appended
claims are
expressed.
