Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02175928 2005-05-17
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AMethod of Operating a Gas Lift Flow Control Device
The present invention relates to a gas lift flow
control device for injecting gas into the production string
of a subterranean well utilizing gas lift equipment and
techniques to enhance the flow of liquids from a geological
formation.
In producing liquids, including water, oil, and
oil with entrained gas, from a geological formation, natural
pressure in the reservoir acts to lift the liquids in a
wellbore upwards to the surface. The reservoir pressure
must exceed the hydrostatic head of the fluid in the
wellbore and any back-pressure imposed by the production
facilities at the surface for the well to produce naturally.
The reservoir pressure can decline over time. requiring
artificial steps to improve lift. One commonly known
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method of augmenting lift is to inject gas into the production
string, or tubing, to decrease the density of the fluid, thereby
decreasing the hydrostatic head to allow the reservoir pressure
to act more favorably on the fluids to be lifted to the surface.
This gas injection is usually accomplished by forcing gas down
the annulus between the production tubing, which conducts
reservoir fluids to the surface, and the casing of the well.
Then the gas is constrained to flow through a gas flow control
device at a predetermined depth into the production tubing. The
gas bubbles mix with the reservoir fluids, thus reducing the
overall density of the mixture and improving lift.
Alternatively, gas and/or relatively less dense fluids from
another formation penetrated by the wellbore can be constrained
to flow into the production tubing to decrease the overall
density of the fluids to be produced from the well. This
procedure, commonly referred-to as autolifting, uses formation
fluids (gas or light hydrocarbon liquids) from another formation
having a formation pressure greater than the formation from which
the liquids to be lifted are produced. Thus, instead of
compressing gas at the surface and injecting the gas down the
casing of the well to the flow control device, another formation
having sufficiently higher pressure is isolated to where the gas
and/or less dense fluid from the isolated formation is
constrained to flow down the annulus between the casing and the
production tubing, through the flow control device, and into the
production tubing, thereby reducing the overall density of the
mixture in the production tubing and providing lift.
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There are two types of gas flow control_devices commonly
employed to control the injected gasinto the production tubing,
namely gas lift valves and orifice valves. Gas lift valves are
normally closed in a biased position whereby a movable stem is
forced upon a matching seat to close the gas lift valve and
prevent the flow of injected.gas therethrough. On the other
hand, orifice valves have no moving parts other than a check
valve to prevent reverse flow therethrough. Therefore, orifice
valves are simply open to flow of injection gas, but are closed
to flow in the opposite direction.
Gas lift valves are used as unloading valves at different
locations throughout the well, and may also be used to control
the injection of the gas at the most optimum point of injection.
Orifice valves are used to control injection gas rates into the
production tubing at the optimum point of injection. In certain
situations, gas lift valves are sometimes considered less
desirable because of their expense and because of their
construction, namely the stem and seat arrangement, obstructs gas
flow. An orifice valve overcomes both of these objections, and,
therefore, is often employed at the optimum point of injection.
The valve that is installed at the optimum point of injection is
commonly called the operating valve.
Flow instability is a common problem existing in wells which
employ continuous-flow gas lift. Flow instability results in (1)
large fluctuations in the production flow rate, (2) large
fluctuations in the gas injection rate, and (3) large
fluctuations in the pressure of both the tubing and casing.
Understanding the influence that the gas flow control device has
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on flow instability is crucial to understanding the present
invention.
Flow instability in a continuous-flow gas lift well can be
characterized as a cyclic process. As the gas injection rate
through the gas flow control device begins to increase, the
density of the fluid in the production tubing string decreases,
which, in turn, results in more -reservoir fluid entering the
wellbore. This portion of the cycle continues and accelerates
until the pressure in the annulus drops, i.e., the supply of
injection gas in the annulus diminishes. The pressure drop in
the annulus results in a decreasa in the pressure differential
across the gas flow control device and, thus, a decrease in the
rate of gas injection through the gas flow control device and
into the production tubing. As a result of the decrease in the
gas injection rate through the gas flow control device, the
density of the fluid in the tubing string increases, causing the
production pressure, or downstream pressure, to increase, which,
in turn, results in less reservoir fluid entering the wellbore.
This part of the cycle continues until the pressure in the
annulus increases sufficiently to where the rate of gas injection
through the gas flow control device once again increases.
The differential pressure across the gas flow control device
is defined as the difference between the injection pressure and
the production pressure. The differential pressure can also be
listed as a percentage of the injection pressure. In this
context, the injection pressure is also referred to as either the
upstream or casing pressure, and the production pressure is also
referred to as either the tubing-or downstream pressure.
~ WO 96/07813 p4 't PCT(GB95102079
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Flow instability in continuous-flow gas lift wells occurs
where the gas flow control device allows the gas injection rate
through the device to fluctuate as a function of the production,
or downstream, pressure. The gas injection rate through a prior
art square-edgedorifice gas flow control device fluctuates as
a the production, or downstream, pressure fluctuates.
Choking at the flowline downstream from the production
tubing string is the accepted industry practice that is used to
lessen the effect of the above mentioned factors which cause flow
instability. Choking typically increases the average flowing
bottom hole pressure in the tubing to be higher than desired.
This, in turn, reduces the rate of fluid that is produced from
the reservoir. To compensate for flowline choking, more gas
injection is required. This increase in gas injection adversely
affectsthe efficiency of the gas lift operation because of the
increase in lifting costs and the inefficient use of injection
gas.
Fluctuations in the bottom hole tubing pressure cause
fluctuations in the rates of gas flowing through the flow control
device; i.e., with large bottom hole tubing pressure decreases,
the gas injection rate through the flow control device increases.
This phenomena is largely uncontrollable and unpredictable using
existing gas flow control devices.
The aforementioned fluctuations in tubing pressure may also
result in problems at the surface. For instance, segregated
flows of oil and gas mixtures can be forced up the production
tubing to the surface, resulting in severe pressure surges
throughout the tubing and within the surface equipment. This
WO 96/07813 PCT/GB95/02079
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phenomena is commonly referred to as slugging._ when the
segregated fluids from the well reach the production facility and
enter the first stage separator, the particular instantaneous
flow rate, or surge, of liquids may exceed the flow capacity of
the senarator, causing liquid carryover into the gas lines. This
can lead to repeated costly shut downs and loss of revenue from
all wells leading into that particular facility.
The average bottom-hole flowing pressure in the tubing
during unstable flow is-significantly higher than during stable
flow. During slugging, the bottom-hole flowing pressure-in the
tubing increases due to the higher density fluid present in the
tubing string. The pressure increase is further aggravated by
the prior art flow control device because it passes less gas as
the bottom-hole flowing pressure in the tubing increases, thereby
providing less gas into the tubing.
Accordingly, there is a need to provide a gas flow control
device which increases the production rate of, and stabilizes the
flow of production from, a continuous-flow gas lift well.
There is a further need to achieve improved performance with
both an improved orifice valve and an improved gas lift valve
that are used as gas flow control devices.
There is a further need to provide a gas flow control device
having a consistent and predictable gas injection rate.
There is also a need to provide a gas flow control device
which has a reduced sensitivity to fluctuations in tubing
pressure.
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There is still a further need to provide a gas flow control
device whereby the lift gas injection rate can be controlled from
the surface.
The present invention overcomes the deficiencies of the
prior art.
SUMDSARY OF THE INVENTION
To address the above-described problems with, and
deficiencies of, the prior art, it, is a primary object of the
present invention to provide a gas flow control device through
which a predictable and constant gas injection rate can be
established, and which overcomes the flow instability that
commonly occurs in gas lift wells.
It is a further object of the present invention to provide
an improved gas flow controldevice whereby the gas injection
rates through the gas flow control device are controllable at the
surface.
It is a further object of the present invention to provide
a method of increasing the production rate of a continuous-flow
gas lift well.
It is a further object of the present invention to provide
a method of stabilizing the production from a continuous-flow gas
lift well.
It is still a further object of the present invention to
provide an improved gas flow control device for injecting gas
into a production string whereby the injection gas pressure
within the flow control device is recovered and frictional losses
through the gas flow control device ate reduced, thereby
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establishing critical flow at a lower differential pressure
across the gas flow control device.-
It is still a further object of the present invention to
provide a method of eliminating the effect of tubing pressure on
the gas injection rate through a gas_flow control device utilized
in a continuous-flow gas lift well. --
In an established continuous-flow gas lift system, there are
five major independent variables which affect the instability of
a well and its rate of-production, namely, the tubing pressure
at the gas flow control device, the casing pressure at the gas
flow control device, the gas injection rate through the gas flow
control device, the orifice geometry within the gas flow control
device, and the propensity for, or the ability of, the formation
to produce liquids. It is a primary object of the invention to
provide a gas flow control device which reduces the instability
in the continuous-flow gas lift well by minimizing the effect of
one major variable, the tubing pressure at the gas flow control
device. Minimizing the effect of tubing pressure is achieved by
means of controlling three of the remaining major variables,
namely the casing pressure, the gas injection rate, and the
geometry within the gas flow control device.
Accordingly, the gas flow control device of the present
invention controls the rate at which gas is injected into a
production string and includes a housing with at least one inlet
port, at least one outlet port and a nozzle-Venturi orifice. The
nozzle-Venturi orifice, which may also be referred to as a
circular-arc-Venturi, is a converging-diverging pathway that is
made of two parts: a nozzle portion and a Venturi tube, or
WO 96/07813 PCT/6B95102079
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Venturi portion. The nozzle portion includes first and second
ends, and a flow path therebetween. The nozzle portion
converges, or is progressively restrictive, from the nozzle first
end to the nozzle second end.- The Venturi portion includes a
first and a second end, and a flow path therebetween. The first
end of the Venturi tube, also referred to as a Venturi for
simplicity, is disposedadjacent to the second end of the nozzle
portion. The Venturi portion diverges, or is progressively
larger, between the Venturi first end and the Venturi second end.
The Venturi flow path is aligned with the nozzle flow path to
provide a continuous flow path through the device. Pressurized
gas from the annulus between the casing and production tubing is
constrained to flow through the at least one inlet port, through
the continuous flow path, through the at least one outlet port,
and into the production tubing.
In a preferred embodiment of_the invention, the nozzle
portion of the gas flow control device includes curvilinear
sidewalls extending from the nozzle first end to the nozzle
second end.
In a preferred embodiment of the invention, the diameter of
the nozzle first end is greater than the diameter of the nozzle
second end. Further, the diameter of the Venturi first end is
equal to the diameter of the nozzle first end and lessthan the
diameter of the Venturi second end.
In a preferred embodiment of the invention, the cross
sectional area of the nozzle first end is greater than the cross
sectional area of the nozzle second end. The cross sectional
area of the Venturi first end is equal to the cross sectional
WO 96/07813 PCT/GB95102079 ~
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area of the nozzle second end and less than the cross sectional
area of the Venturi second end.
in a preferred embodiment of the invention, the ratio of the
cross sectional area of the nozzle second end to the cross
sectional area of the nozzle-first end is approximately 0.4.
In a preferred embodiment of the invention, the ratio of the
cross sectional area of the nozzle second end to the cross
sectional area of the nozzle first end is less than 0.4.
In a preferred embodiment of the invention, the gas flowing
through the gas flow control device achieves critical flow at a
differential pressure of less than 46% of the gas injection
pressure. Here, the differentialpressure is the difference
between the gas injection pressure and the production pressure.
In a preferred embodiment of the invention, gas flowing
through the gas flow control device achieves critical flow at a
differential pressure of between approximately 4% and 10% of the
gas injection pressure.
In a preferred embodiment of the invention,'the gas flowing
through the gas flow control device achieves critical flow at a
differential pressure of between approximately 5%; and 46%- of the
gas injection pressure.
In a preferred embodiment of the present invention, gas
flowing through the gas flow device achieves critical flow at a
differential pressure of less than 10% of the gas injection
pressure.
In a preferred embodiment of the invention, the nozzle
portion includes curvilinear sidewalls extending from the nozzle
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WO 96/07813 PGT/GB95102079
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first end to the nozzle second end. The sidewalls have a radius
of curvature greater than the diameter of the nozzle second end.
In a preferred embodiment of the invention, the nozzle
portion includes curvilinear sidewalls extending from the nozzle
first end to the nozzle second end. The sidewalls have a radius
of curvature equal to about 1.5 to about 2.5 times the diameter
of the nozzle second end. -
In a preferred embodiment of the invention, the nozzle
portion includes curvilinear sidewalls extending from the nozzle
first end to the nozzle second end, and the sidewalls have a
radius of curvature equal to about 1.9 times the diameter of the
nozzle second end_
In a preferred embodiment of the invention, the Venturi
portion includes Venturi walls that extend from the Venturi first
end to the Venturi second end. The Venturi walls form an angle
of about 4 degrees to about 15 degrees with respect to the
longitudinal axis of the Venturi flow path.
In a preferred embodiment of the invention, the Venturi
portion includes Venturi walls extending from the Venturi first
end to the Venturi second end. The Venturi walls form an angle
of about 6 degrees with respect to the longitudinal axis of the
Venturi flow path.
In a preferred embodiment of the invention, the Venturi
portion includes Venturi sidewalls that are circular in cross
section and extend from the Venturi first end to the Venturi
second.
In accordance with the present invention, a method of
controlling the rate of gas injected into a production tubing
WO 96/07813 PCT70B95/02079
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string is provided. The tubing string is positioned within a
well and concentric to casing, forming an annulus therebetween.
A gas flow control device .is placed within the well at a
predetermined location, the gas flow control device comprising
a housing including at least one inlet port and at least one
outlet port, and an orifice comprising a nozzle portion and a
Venturi portion, the nozzle portion including a nozzle first end,
a nozzle second end, and a nozzle flow path between the nozzle
first end and the nozzle second end, the nozzle flowpath
converging from the first nozzle end to the second nozzle end,
and the Venturi portion including a first end and a second end,
and a Venturi flow path therebetween, the Venturi flow path
diverging from the Venturi first end to the Venturi second end,
the Venturi first end being disposed adjacent the nozzle second
end, the Venturi flow path being aligned with the nozzle flow
path to provide a continuous flow path, the gas flow control
device positioned for transmitting the flow of injected gas from
the annulus into the production tubing string. Compressed gas
is forced into the annulus. The compressed gas is constrained
to flow through the gas flow control device to mix the gas with
reservoir fluids within the production tubing string, thereby
reducing the density of the reservoir fluids. The pressure of
the gas forced into the annulus is controlled with a pressure
control device, thereby increasing the gas injection rate through
the gas flow control device by increasing the pressure of the gas
in the annulus, and decreasing the gas injection rate through the
gas flow control device by decreasing the pressure of the gas in
the annulus.
~WO 96/07813 2~ ~ ~ ~ w ~ PCT(GB95l02079
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In accordance with the present invention, a method is
provided for eliminating instability in a production tubing
string of a continuous-flow gas lift well. The production tubing
string is positioned within said well and concentric to casing,
said casing and said concentric production tubing string forming
an annulus therebetween. A gas flow control device is positioned
within said well at apredetermined location, said gas flow
control device comprising a housing including at least one inlet
port and at least one outlet port; and an orifice comprising a
nozzle portion and a Venturi portion; said nozzle portion
including a nozzle first end, a nozzle second end, and a.nozzle
flow path between said nozzle first end and said nozzle second
end, said nozzle flowpath converging from said first nozzle end
to said second nozzle end; and said Venturi portion including a
first end and a second end, and a Venturi flow path therebetween,
said Venturi flow path diverging from said Venturi first end to
said Venturi second end, said Venturi first end being disposed
adjacent said nozzle second end, said Venturi flow path being
aligned with said nozzle flow path to provide a continuous flow
path; said gas flow control device positioned for transmitting
the flow of injected gas from the annulus into the production
tubing string. Compressed gas is forced into the annulus. The
compressed gas is constrained to flow through said gas flow
control device to mix said gas with reservoir fluids within the
production tubing string, thereby reducing the density of said
reservoir fluids. The pressure of the gas forced into the
annulus is controlled with a pressure control device to achieve
critical fiow through the gas flow control device, thereby
WO96/07813 PCT/GB95/02079 ~
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maintaining a constant gas injection rate across said gas flow
control device that is independent of the pressure within the
production tubing string.
In accordance with the present invention, a method of
eliminating instability in continuous-flow gas lift wells is
provided by stabilizing the gas injection rate through the gas
flow control device so that the gas injection rate is independent
of the typical tubing pressure fluctuations that occur in a
continuous-flow gas lift well.
It is contemplated that fluids, namely both gas and liquids,
can be used for the lifting of formation fluids to the surface.
Accordingly, while the present invention refers to "gas lift" and
"gas flow control devices," it is contemplated that fluids,
having relatively lower density than the formation fluids to be
lifted, can be injected through the flow control device into the
production tubing to decrease the density of the mixture to
improve lift.
The foregoing has outlined-the features and-technical
advantages of the present invention so that those skilled in the
art may better understand the detailed description of the
invention that follows. Features and advantages of the invention
that are described above and hereinafter form the subject of the
claims of the invention. Those skilled in the art should
appreciate that they may readily use the conception and the
specific embodiment disclosed as a basis for modifying or
designing other structures for carrying out the same purposes of
the present invention.
~ PCT/GB95102079
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In order that the invention may be more fully
understood, embodiments thereof,(and the prior art) will
now be described by way of illustration only, with reference
to the accompanying drawings, wherein:
FIG. 1 shows a graph which illustrates orifice gas
injection rate performance in a typical, prior art high
pressure gas lift system. The graph is a plot of gas flow
rate (ordinate) and tubing pressure in psi (abscissa), where
the casing pressure is held constant at 1600 psi. The
region A is the critical flow regime.
FIG. 2 shows a graph which illustrates orifice gas
injection rate performance in a typical, prior art low
pressure gas lift system. The graph is a plot of gas flow
rate (ordinate) and tubing pressure in psi (abscissa), where
the casing pressure is held constant at 1000 psi. The
region A is the critical flow regime.
FIG. 3 shows a graph which illustrates the desired
gas injection rate performance in a gas flow control device
to eliminate instability in a continuous-flow gas lift well.
The graph is a plot of gas flow rate (ordinate) and tubing
pressure in psi (abscissa), where the casing pressure is
held constant at 1000 psi. The region A is the critical
flow regime.
FIG. 4 illustrates a cross-sectional, side-
elevational, diagrammatic view of the environment of a gas
injection control device;
FIG. 5 illustrates a cross-sectional view of a
standard orifice gas injection control device having a
square-edged orifice;
FIGS. 6A and 6B illustrate a cross-sectional view
of an exemplary orifice gas flow control device of the
present invention including a nozzle-Venturi orifice;
FIG. 6C illustrates a cross-sectional view of a
nozzle-Venturi orifice assembly that is included within a
gas flow control device of the present invention;
FIGS. 7A and 7B illustrate a cross-sectional view
W O 96107813 ryC (~q ; '~' ~ PCT/GB95/02079 ~
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of an exemplary gas lift valve of the present invention
including a nozzle-Venturi orifice;
FIG. 8 shows a graph which illustrates the dynamic
performance of an exemplary nozzle-Venturi gas flow control
device of the present invention at three separate upstream
pressures, and also provides a comparison to the dynamic
performance of a prior art gas flow control device employing
a square-edged orifice, shown in FIG. 2. The graph is plots
of gas injection rate (MCF/D) (ordinate) and downstream
pressure in psi (abscissa) at upstream pressures of 400 psi
(line D), 900 psi (line E), 900 psi (line F) and 1400 psi
(line G).
FIG. 9 shows a graph which compares a pressure
profile for a square-edged orifice housed in a prior art gas
flow control device and a pressure profile for an exemplary
nozzle-Venturi orifice housed in a gas flow control device
of the present invention. In the graph, the left-hand
ordinate is the upstream pressure in psi, and the right-hand
ordinate is the downstream pressure in psi. The abscissa is
the distance. Line P is prior art and line Q is according
to the invention.
To illustrate the influence of a prior art square-
edged orifice used in a gas flow control device, FIG. 1
shows a typical performance thereof. The casing pressure of
the wellbore, at the depth of gas injection through the
device, is a constant 1600 psig, and the desired tubing
pressure is 1450 psig. The casing pressure is defined as
the upstream pressure of the orifice, and the tubing
pressure is defined as the downstream pressure of the
orifice. As the tubing pressure increases, the gas
injection rate through the orifice decreases. Conversely,
as the tubing pressure decreases, the gas injection rate
through the orifice increases.
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PCTlGB95102079
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FIG. 2 also illustrates the effect of the prior art orifice
used in a gas flow control device. In this illustration, the
prior art orifice is provided in an environment at lower casing
and tubing pressures of 1000 psig and 850 psig, respectively.
Typically the desired pressure drop across the prior art
orifice is between 100 and 200 psi. However, at pressure drops
of 150 to 200 psi, high injection pressures are required,
resulting in high gas compression costs. Where the pressure drop
is under 100 psi, the gas injection rate becomes more
unpredictable. Thus, a pressure drop of under 100 psi is usually
not considered due to the lack of accurate data and the potential
of designing an inefficient gas lift system. Accordingly, a
pressure drop in excess of 100 psi across the prior art orifice
is typically desired and used as a safety factor in designing the
gas lift system.
As evidenced by FIGS. 1 and 2, and as known in the art, the
gas injection rate through the prior art orifice continues to
increase until the tubing pressure declines to a value that is
about 54k of the constant casing pressure. Thereafter, the gas
injection rate through the orifice remains constant as the tubing
pressure is lowered. The industry properly understands that
critical flow through the prior art square-edged orifice is
established when the tubing pressure is about 54k of the casing
pressure. When the tubing pressure drops to the critical flow
regime (i.e., the tubing pressure is 54V of the casing pressure),
the gas injection rate through the orifice remains constant and
independent of the tubing pressure.
W0 96l07813
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Establishing the critical flow regime through the orifice
acts to eliminate flow instability. For example, for the well
operating at a tubing pressure of 1450 psig, establishing
critical flow through the prior_ art, square-edged gas flow
control device could be established by increasing the casing
pressure from 1600 psig to 2700 psig or above. However, creating
such a high pressure drop across the orifice is not economically
feasible due to the additional cost in gas compression.
Furthermore, this practice is not practical due to the increased
likelihood of mechanical problems.
It is an object of the present invention to provide an
orifice valve that seeks to reduce and effectively eliminate flow
instability under normal conditions. Specifically, it is an
object of the present invention to provide a flow control device
which has the performance characteristics that are illustrated
in FIG. 3, where the critical flow regime and a constant
injection rate are reached when the tubing pressure is
approximately 90%-954; or less of the casing pressure, as opposed
to the industry standard of 54k for the prior art, square-edged
orifice.
FIG. 3 is a graph which illustrates the desired flow rate
performance in a gas control deviceof the present invention
where the constant casing pressure is 1000 psig. Therefore, if
the tubing pressure declines below approximately 900 psig the
gas injection rate through the control device remains fixed.
Thus, for a typical pressure drop of 100 to 200 psi. across the
gas flow control device, a constant gas injection rate can be
achieved resulting in a stabilized well and improved economics.
~WO 96/07313 E+ 1~ 5 e7 Z g ~~ ~r a t ~~, PCTlGB95102079
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Another advantage of the orifice valve of the present
invention is the capability of controlling the injection gas rate
through the gas flow control device, without causing instability,
by simply controlling the surface injection pressure. Typically,
this also has the effect of controZling the production rate of
the liauids from the wellbore. Thus, by using the orifice valve
of the present invention downhole, the operator can increase the
pressure of the gas at the surface to increase the injection
pressure (casing or upstream pressure) at the gas flow control
device, which, in turn, increases the differential pressure
across the gas flow control device and, therefore, the rate of
gas injection through the gas flow control device. This, in
turn, decreases the density of the fluid in the production tubing
string, which allows more fluids from the reservoir to enter the
wellbore and be produced. increasing the pressure of the
injected gas increases the density of the gas such that, for the
same restriction in the gas flow control device, the gas
injection rate is increased.
The present invention is employed in an exemplary
environment that is shown in FIG.4. A gas lift well system 10
extends from above ground G, where system 10 is connected to a
pressurized gas source (not shown) and to petroleum recovery
equipment (not shown), and a subterranean petroleum reservoir P.
Petroleum rises in production tubing 12. Pressurized gas is
introduced into annulus 14, which exists between the production
tubing 12 and outer steel casing 16. Annulus 14 is sealed at the
bottom of casing 16 by a packer 18. Pressurized gas is supplied
from a source, such as a compressor (not shown). The gas
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WO 96107813 PCT/GB95/02079 .~
pressure in the annulus 14 is regulated by a pressure control
device 9, namely either an adjustable choke-or a regulator, at
the surface. The pressurized gas, represented by arrows 20,
flows from the compressor, through the pressure control device
9, and through the annulus 14 into tubing 12 via a gas flow
control device 22. Gas injected into production tubing 12
decreases the density of petroleum rising to the surface and
enables natural reservoir pressure to maintain this flow. The
pressure control device 9 is utilized at the surface to control
the pressure in the annulus 14, which, in turn, establishes the
injection pressure (also referred to as the casing pressure or
upstream pressure) at the gas flow control device 22, the
differential pressure across the gas flow control device, and,
thus, the rate of injection through the gas flow control device
22.
While the pressure control device 9 is shown at the surface
in FIG. 4, it is contemplated that a pressure control device can
be installed within the annulus at a depth more proximate the gas
flow control device 22. In this situation, a certain amount of
annulus is isolated to form a chamber for injection gas whereby
the gas to be injected is delivered to the chamber, and the gas
pressure regulated by the pressure control device which, in turn,
is controlled from the surface via a hydraulic or electric
control line.
Furthermore, a single well bore will often times intersect
a number of producing formations and, for economic reasons, these
formations, referred to as production zones, are isolated by
installing packoff devices so that the individual zones can be
WO 96/07813 21 ~~ ~ x 8 PCT/6B95/02079
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produced independently. A plurality of tubing strings are thus
employed to produce the specific formations. The limitations of
the prior art gas flow control device, namely its dynamic
performance, exacerbates the flow instability in well completions
with a plurality of production tubing strings. In such a well,
instability is more likely to occur in each of the individual
production tubing strings of the gas lift system because the
common annulus supplies the injection gas to each gas flow
control device and the injection rate through each prior art gas
flow control device is completely unpredictable and independent.
The present invention rrovides a constant gas injection rate into
each tubing string and will, therefore, diminish the flow
instability common in wells having a plurality of production
strings.
A prior art gas flow control device 22 having a square-edged
orifice is illustrated in FIG. 5. The direction of the gas flow
through the gas flow control device is indicated by arrows 26.
Pressurized gas at injection pressure enters the prior art flow
control device 22 through inlets 24 and flows through a square-
edged orifice 29, containing passage 29a and seal 29b. Gas then
passes through passageway 28a of an orifice holder 28 and past
the check valve 30. Gas is then discharged through outlet 32 at
the nose end 21, at production pressure, anci passes into
production tubing 12 (FIG. 4). The passage 29a and passageway
28a typically have circular cross-sections, when considering
those cross-sections are taken along planes perpendicular to the
longitudinal axis of the gas flow control device.
WO 96/07813 PCT/GB9S/02079
22
FIGS. 6A and 6B illustrates an exemplary gas flow control
device 60 of the present invention. The gas flow control device
60 has generally the same dimensions and components as those of
the prior art gas flow control device 22 (illustrated in FIG. 5),
including a dummy tail section 62, inlet ports 54 and nose end
61 with a check valve 65 and outlet ports 64; the check valve 65
includes a dart 67, a spring 69, and a check seal 71. However,
the gas flow control device 60 of the present invention includes
a nozzle-Venturi orifice 34, instead of the square-edged orifice
29 found in the prior art.
The direction of the gas flow_through the gas flow control
device of the present invention is indicated by arrows. 26.
Pressurized gas at injection pressure (casing pressure) enters
the inlet ports 54 and flows through the nozzle-Venturi orifice
34 and past the check valve 65. The gas is then discharged
through the outlet ports 64, at production pressure (downstream
pressure or tubing pressure), and passes into the production
tubing.
An exemplary nozzle-Venturi orifice 34 is illustrated in
detail in FIG. 6C and may comprise, for example, a circular arc
Venturi, and includes a nozzle portion 34a and a Venturi portion
34b. Nozzle portion 34a lies above a throat 36, and Venturi
portion 34b lies.below throat 36.
Nozzle portion 34a includes sidewalls 38 which offer minimal
resistance to the flow of fluid (gas or liquid) as the fluid
approaches throat 36. Sidewalls 38 are progressively restrictive
to throat 36. The cross-sectional area of throat 36 is less than
PCT/GB95f02079
~WO 96107II13 ~ ~ ~ 5928
23
the cross-sectional area of nozzle portion 34a and Venturi
portion 34b.
Sidewalls 38 are curved, or curvilinear, such that the
slopes of tangent lines measured at each point along the curve
42 of nozzle portion 34a, slope being considered in the
mathematical sense, are greater attangent points approaching
throat 36:- Also, the curvature of nozzle portion 34a is such
that there is a radius of curvature 44 which is greater than a
diameter 46 of the throat 36 by a factor between 1.5 and 2.5, a
preferred value being 1.9.
Below throat 36, Venturi 34b increases in cross-sectional
area at a rate such that vertical walls 48 thereof form an angle
50 to a vertical, or longitudinal, direction 52. Angle 50 lies
within a range of four to fifteen degrees, a preferred value
being six degrees. -
The ratio of the cross-sectional area at the diameter 46 of
throat 36 to the cross-sectional area at the widest point of
nozzle portion 34a, as measured at the mouth 54, is equal to or
less than 0.4.
Cross-sections of nozzle-Venturi orifice 34, including
cross-sections of the nozzle portion and the Venturi portion,
considering those cross-sections taken along planes perpendicular
to the Venturi axis, are generally represented as being circular.
This is due to the expectation that manufacturing processes for
forming nozzle-Venturi orifice 34, or for forming a die or mold
to manufacture the same will be centered around cutting a
rotating piece of stock, as exemplified by a lathe operation.
However, it is contemplated that othermanufacturing processes
WO 96ro7s13
Zjj5S%S PCT/GB95/02079
24
are possible, and that other geometries for the cross-sections
of the nozzle portion and Venturi portion are thus possible. For
example, corresponding cross-sections of nozzle-Venturi orifice
34 may be rectangular, elliptical, polygonal, hypergeometric
elliptical, or even of other configurations.
Gas flowing within nozzle portion 34a of nozzle-Venturi
orifice 34 flows at a high velocity and a low pressure. The gas
flowing through Venturi portion 34b decreases in velocity and
increases in pressure such that the gas exiting the valve 22 has
pressure recovered with a minimal amount of energy or pressure
loss.
For optimum performance, the nozzle portion 34a and the
Venturi portion 34b of the nozzle-Venturi orifice_34 should be
made of low-friction materials, such as ceramics, highly polished
metals and plastics. Thus, the frictional losses across the
nozzle-Venturi are minimized. The material used in the orifice
valve that was tested was made of 17-ph stainless.
FIGS. 7A and 7B illustrate another preferred embodiment of
a gas flow control device of the present invention, where a
nozzle-Venturi orifice is housed within an artificial lift valve,
also commonly referred to as a gas lift valve. Referring now to
FIGS. 7A and 7B, an exemplary artificial lift valve 200 is
illustrated in detail, which is representative of artificial lift
valves enclosed within a side pocket mandrel included in
production tubing. It should be understood that the
configuration described for this artificial lift valve is for
purposes of explanation only and is not intended to limit the
invention to a particular construction of artificial lift valve.
~WO 96/07813 2171; li 2p PCT/GB95102079
ele7 0
Although the construction and general operation of artificial
lift valves and their components are well known, this will be
described in some detail to provide background and to aid the
reader in an understanding of the invention.
As illustrated in FIGS. 7A-7B, in a preferred embodiment of
the invention the artificial lift valve 200 is made up of a valve
housing, indicated generally at 202, which is shaped and sized
to reside within the bore_ 204 of a side pocket mandrel in
production tubing. It is noted that the bore 204 of the side
pocket mandrel includes a number of generally radially outward
facing lateral ports 206 which permit fluid communication between
the interior of the bore 204 and the wellbore annulus 14 (as
shown in FIG. 4). The lower portion of the bore 204 also
features one or more radially inward-facing apertures (not shown)
which will permit fluid communication between the interior of the
bore 204 and the flowbore within the tubing string 12 (as shown
in FIG. 4). Side pocket mandrel designs of this nature are
widely known.
The valve housing 202 itself includes an upper dome sub 208
which is threadedly connected at 210 to a bellows housing 212
below. The upper end of the upper dome sub 208 features a
threaded portion 214 which permits the valve housing 202 to be
engaged with a latchable member 216 (latchable portion not shown)
for secure fastening of the valve 200 within the bore 204 of the
side pocket mandrel. The bellows housing 212 is threadedly
engaged at 218 at its lower end to a connector sub 220 which, in
turn, is threadedly attached to a main valve housing 224. The
main valve housing 224 carries an outer annular elastomeric
WO 96/07813
(rt) 1ryC f128 PCT/GB95/02079
l J~7 26
packing 226 which, when the valve 200 is disposed within the bore
204, effects a fluid seal against the inner surface of the bore
204. The main valve housing 224 also presents one or more
lateral ports 228 which permit fluid transmission through the
main valve housing 224. A valve seat retainer 230is affixed by
threaded connection 232 to the lower end of the main valve
housing 224. A nozzle-Venturi housing 234 is threaded at 236 to
the valve seat retainer 230 and carries an outer annular packing
238 about its circumference which, when the valve 200 is disposed
within the bore 204, effects a fluid seal against the inner=
surface of the bore 204. Finally, a tapered nose piece 240 is
threaded at 242 to the nozzle-Venturi housing 234.
A nitrogen charged chamber or "dome" chamber 244 is located
near the top of the valve 200. A fill valve 246 and a removable
threaded main seal plug 248 are located thereabove.
Below the dome chamber 244, a main valve assembly 250 is
reciprocally disposed within a bellows chamber 252 and a main
valve chamber 253 which is defined by the main valve housing 224.
A reduced diameter neck 254 is located at the upper portion of
the bellows chamber 252 and separates the bellows chamber 252
from the dome chamber 244 above. The main valve assembly 250 is
made up of upper, central and lower stem sections 256, 258 and
260, respectively, which are threadedly connected to each other
in an end-to-end relation as shown. The main valve assembly 250
also features a valve plug 262 with a downwardly presented
spherically-shaped closure member, or ball, 264 threadedly
engaged to the bottom of the lower-stem section 260. Below the
fl PCT/GB95l02079
=WO 96/07813 217528
el 27
valve plug 262, a valve seat 266 is maintained in place within
the main valve chamber 253 by the valve seat retainer 230.
The upper stem section 256 of the main valve assembly 250
is disposed through the reduced diameter neck 254. A series of
small annular baffles 268 circumferentially surround portions of
the upper stem section 256 which are sized and shaped to receive
small amounts of viscous fluid and thus, during movement of the
main valve assembly 250, serve to dampen vibration.
Within the bellows chamber 252, and generally radially
surrounding the central stem section 258, is an accordion-like
bellows 270 which will axially extend and retract within the
bellows chamber 252. The bellows 270 is made of a flexible,
waterproof material. A compression spring 255 is located within
the bellows chamber above the main valve assembly 250 to limit
excessive upward travel of the main valve assembly 250 and
overcompression of the bellows 270.
Two mutually opposing fluid pressure conducting passages,
separated by the bellows 270, are used to control the opening and
closing of the main valve assembly 250 due to the fluid seals
created between the bore 204 of the surrounding side pocket
mandrel and packings 226 and 238. The first pressure conducting
passage, generally at 272, includes the dome chamber 244 and the
bellows chamber 252. Pressure within this first pressure
conducting passage is maintained radially outside of the bellows
270. The first pressure conducting passage 272 is pressurized
prior to disposal of the artificial lift valve 200 into the
wellbore. The bellows chamber 252 is filled with a viscous fluid
until the fluid covers the reduced diameter neck 254 and reaches
W096/07813 PCT/GB95102079
2175929 ' Y,;~ "
28
a level 274 within the dome chamber 244. The dome chamber 244
is then charged with nitrogen through the fill valve 246 prior
to being run into the wellbore so as to provide a fluid spring
by removing the plug 248 and forcing nitrogen through the fill
valve 246 under pressure.
The second pressure conducting passage 276 includes the main
valve chamber 253. Fluid and fluid pressure from the wellbore
annulus 320 enters the main valve chamber via ports 228. Fluid
entering the main valve chamber 253 is maintained radially within
the bellows 270.
Resultant pressure within the second pressure conducting
passage 276 acts upon the main valve assembly 250 in counterpoint
to that provided by the fluid spring of the first pressure
conducting passage 272. When the pressure within the second
pressure conducting passage 276 overcomes that provided by the
fluid spring, the closure member 264 (ball) will be lifted from
the seat 266 to permit flow of fluid entering ports 228 to flow
downward past the seat 266 and into and through the nozzle-
Venturi orifice 34 defined within the nozzle-Venturi housing 234.
The nozzle-Venturi orifice 34 (as shown in detail in FIG. 6C)
extends downward to and past a check valve assembly 280 at the
lower end of the valve 200. Therefore, fluid entering the
nozzle-Venturi orifice 34 downward past the valve seat 266 can
move downward through the nozzle-Venturi orifice 34, out of the
lower end of the tralve 200 and into the lower portion of the bore
204 where it may enter the production tubing string through
apertures in the mandrel below.
WO 96/07813 PCT/GB95102079
29
A nozzle-Venturi orifice 34 is maintained within the nozzle-
Venturi housing 234 and aligned so that the gas will pass
downward through the nozzle-Venturi orifice 34 and out of the
lower end of the valve 200. The arrangement of the nozzle-
Venturi is best seen by referring once again to FIG. 6C.
In a typical gas lift valve, the combination of the movable
stem and seat defines a pressure-adjustable orifice and, in prior
art gas lift valves, the larger the ball and seat size, the more
that the tubing pressure affects the opening and closing of the
valve. Fluctuating tubing pressures can cause the valve to open
and close erratically, causing erratic injection rates that may
further aggravate the fluctuating tubing pressures.
Additionally, prior art gas lift valves are subject to all of the
limitations described above that are related to pressure recovery
through the assembly. In comparison, a gas lift valve of the
present invention will have improved pressure recovery and an
increased gas injection rate due to lower frictional losses
across the gas lift valve, thereby increasing the efficiency of
the gas lift system. Furthermore, the gas lift valve of the
present invention will also be less susceptible to fluctuations
in the injection rate. In the gas lift valve of the present
invention, a converging-diverging, or nozzle-Venturi, orifice
downstream of the ball and seat will result in a constant
pressure below the ball and seat and injection of the gas at a
constant critical flow rate which is determined by the physical
geometry of the valve and orifice. Compared to the prior art gas
lift valve, a gas lift valve of the present invention will have
R'O 96/07813 21 15al Fr 8 PC'1'/GB95102079
r~
a lower differential pressure at which critical flow across the
gas lift valve will occur.
FIG. 8 is a graph which illustrates test results showing the
dynamic performance of anexemplary nozzle-Venturi orifice gas
flow control device of the present invention, as shown in FIGS.
6A and 6B, and the dynamic performance of a conventional gas flow
control device having a square-edged orifice, as shown in FIG.S.
A gas flow control.device of the present invention, which
included a nozzle-Venturi orifice 34 having a throat diameter
(item 46 of FIG. 6C) of 0.332 _inches, was tested at three
separate constant upstream (injection or casing) pressures,
namely 400 psi, 900 psi and 1400 psi. Further, test results of
the dynamic performance of the injection gas flow control device
of the present invention having the present nozzle-Venturi
orifice 34 at a constant upstream pressure of 900 psi, which is
represented by the curve including point A, is compared to test
results of the dynamic performance of a prior.artinjection gas
flow control device, namely a standard orifice valve, having a
square-edged orifice 29 (as shown in FIG. 5). The test results
for the prior art, square-edged orifice valve are indicated by
the curve including point B. Both of the gas flow control
devices had the same diameter of 0.322 inches, and both were
tested at a constant upstream pressure of 900 psi. The sonic
(critical) flow rate regime is that portion of each curve that
is horizontal. By operating a gas injection flow control device
in the sonic flow regime, a stable gas lift system is achieved.
It is readily appreciated that the broad flat portion between the
vertical axis and point A, representing stable performance of a
WO 96/07813 PCT/GB95l02079
r ~1 ?59,~~
31
gas flow -control device of the present invention. including a
nozzle-Venturi orifice 34, is much wider than the corresponding
flat portion between the vertical axis and point B, representing
stable performance of a prior art gas control device, namely a
conventional orificevalve including a square-edged orifice.
Moreover, at similar production pressures, more gas flows through
a gas flow control device with a nozzle-Venturi orifice 34 than
through a gas flow control device with a square-edged orifice
having the same throat size.
Listed below are the test results achieved for various-sized
flow control devices of the present invention, namely orifice
valves including certain sized nozzle-Venturi orifices, at
various upstream (injection) pressures. The results listed are
the downstream pressures, in terms of percentages of the upstream
pressure, at which critical flow across the flow control devices
was reached, which is designated as Point A in FIG. 8.
Alternatively, the resulting differential pressure at which
critical flow across the flow control devices was reached in the
tests is readily calculated as a percentage of the injection
pressure by subtracting a given downstream pressure, listed as
a percentage of the injection pressure, from 100g.
Downstream Pressure As A
Percentage of injection Pressure
At Which Critical Flow Is Reached
Upstream
(Injection)
Pressure (PSIG)
R'0 96/07813 2175928 PCT/GB95/02079
et 32
400 ~ 92.8% 92.8% 95.2% 92.8% 93.2%
900 i 94.5% 94.5% 95.6% 93.4% 92.3%
1400 94.7% 94.7% 95.1% 90.1% 92.2%
0.204 0.266 0.314 0.326 0.332
Orifice Throat Size In Inches
(See Item 46, FIG. 6C)
The gas flow control device of the present invention
including the nozzle-Venturi orifice 34 provides for a lower
pressure drop in achieving sonic, or critical, flow. Square-
edged orifices typically require a pressure drop of 46 percent
of upstream pressure to produce sonic velocity flow therethrough.
In contrast, as illustrated by the table above, thegas control
device of the present invention including a nozzle-Venturi
orifice typically requires less than a ten percent pressure drop
of upstream pressure, and often less than 6 percent pressure drop
of upstream pressure to achieve critical flow. The ability of
the gas flow control device to achieve critical flow at such a
low pressure drop causes the gas injection rate through the gas
flow control device to be generally independent of the tubing
pressure, effectively eliminating flow instability as described
above. In addition to the gas injection rate being independent
of the production tubing pressure, the gas injection rate through
the gas flow control device can be controlled by adjusting the
injection pressure at the surface, which acts to increase or
~WO96107813 PCTlGB95l02079
33
decrease the pressure and the density of the injected gas in the
annulus.
In order to further explain the difference in the flow
performance of a prior art gas flow control device having a
square-edged orifice and the flow performance of an exemplary gas
flow control device of the present invention having a nozzle-
Venturi orifice, FIG. 9 illiistrates the pressure profiles of each
device. The upper portion of FIG. 9 shows an overlay of the
cross-sectional views of the two devices taken along the flow
path of the injected gas, with the dotted line representing the
a square-edged orifice and, the solid line with hatching
representing the nozzle-Venturi orifice. The arrow in the upper
portion of FIG. 9 indicates the direction of the flow of injected
gas through the two devices.
The lower portion of FIG. 9 is a graph that plots the gas
pressure within the devices as a function of the position of the
gas as it flows through the devices. The dotted line represents
the pressure profile for the square-edged orifice of the prior
art gas flow control device and the solid line represents the
pressure profile of the nozzle-Venturi orifice of the gas flow
control device of the present invention. For an injection
pressure of 1000 psia, the sonic flow at the throat (the critical
flow regime) is established for both devices. For air flow this
corresponds to a pressure of approximately 540 psia at the
throat. This flow condition results in the maximum mass flow
rate as indicated by points A and B in figure 8, for the nozzle-
Venturi and the square-edged orifice respectively. After the
throat, where the greatest velocity and the lowest pressure
i a
WO 96/07813 ~~~ ~~ q{2 PCT/GB95/02079 ~
34
occurs, the pressure increases (recovers) and the velocity
decreases in the direction of the flow. For the nozzle-Venturi
a maximum pressure of-900 psia is attained at the exit of the
divergent section. The pressure recovery for the square-edged
orifice is only slight, resulting in the exit pressure of, for
example, 600 psia. Therefore, the sonic flow for a nozzle-
Venturi flow control device can be achieved at a much lower
pressure differential resulting in a higher exit or production
pressure, as compared to a square-edged orifi.ce flow control
device.
It therefore can be seen that the present nozzle-Venturi
provides for a gas flow control -device that minimizes well
instabilities by extending the critical flow rate regime, and by
rendering lift operations independent of production pressure.
The gas flow control device of the.present invention thus acts
to stabilize the flow of production in the production tubing.
The gas flow control device of the present invention
achieves critical flow, that point where any additional pressure
drop in the tubing will not result in an increase of flow through
the valve, with a pressure drop of approximately 5k of the
upstream pressure or greater. Because stable flow through the
gas lift valve is established with such a minimum pressure drop,
there is no need to have a finite control of the injection gas
on the surface.
Although the present invention and its advantages have been
described in detail, those skilled in the art should understand
that they can make various changes, substitutions and alterations.
