Note: Descriptions are shown in the official language in which they were submitted.
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PCT PATENT APPLICATION
ELECTRICAL SUBMERSIBLE PUMP FLOW METER
Inventors: Jinjiang XIAO
Randall Alan SHEPLER
BACKGROUND OF THE INVENTION
1. Cross-Reference to Related Application
[0001] This application is a continuation in part of and claims priority to
and the benefit of
co-pending U.S. Patent Application Serial No. 13/546,694, filed July 11th,
2012, which
claimed priority from U.S. Provisional Application Serial No. 61/540,639,
filed September
29, 2011, the full disclosures of which are incorporated by reference herein
in their entireties
and for all purposes.
2. Field of the Invention
[0001] The present invention relates to electrical submersible pumps. More
specifically, the
invention relates a flow meter used in conjunction with an electrical
submersible pump.
3. Description of the Related Art
[0002] In hydrocarbon developments, it is common practice to use electric
submersible
pumping systems (ESPs) as a primary form of artificial lift. ESPs often use
downhole
monitoring tools to supply both temperature and pressure readings from
different locations on
the ESP. For example, intake pressure, discharge pressure, and motor
temperature, as well as
other readings may be taken on the ESP.
[0003] If wells are producing below bubble point pressure, the liberated gas,
at the surface,
may not allow the surface meters to provide accurate flow rates. To replace
the surface
single phase meters with multi-phase meters can cost tens of thousands of
dollars per well.
Downhole at the ESP a significant percentage of wells are producing with
intake pressures
well above the bubble point pressure. Therefore, being able to measure flow
rate down hole
at the ESP would allow for an accurate flow meter that will assist immensely
in extending the
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life of the ESPs. Therefore, a low cost and accurate flow meter that will
assist immensely in
extending the life of the ESPs that incorporates these theories would be
desirable.
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SUMMARY OF THE INVENTION
[0004] Disclosed herein is an example of an apparatus for monitoring a flow of
fluid in a
subterranean well, and that includes a first pipe section selectively disposed
in the flow of
fluid, a first pressure sensor on the first pipe section that measures a first
pressure loss of the
flow of fluid along at least a portion of the first pipe section, the first
pressure loss made up of
first gravitational losses and first frictional losses, a second pipe section
spaced axially away
from the first pipe section and that is selectively disposed in the flow of
fluid, a second
pressure sensor on the second pipe section that measures a second pressure
loss of the flow of
fluid along at least a portion of the second pipe section and that is made up
of second
gravitational losses and second frictional losses, the second pipe section
having an outer
diameter that is less than an outer diameter of the first pipe section so that
the second
frictional losses are negligible with respect to the second gravitational
losses, a controller in
communication with the first and second pressure sensors and that calculates a
pressure
gradient along a portion of the second pipe section based on the equation PG =
(g)(pm)/((ge)(144)), and a communication media in communication with the
controller and
with the first and second pressure sensors, so that signals representing the
first and second
pressure losses are communicated to the controller. In an embodiment, the
first and second
pressure sensors each have sensor systems having axially spaced apart sensors
that measure a
pressure gradient. The apparatus can further have pressure transmitters in
communication
with the first and second sensors and the communication media. The first and
second pipe
sections can be coupled together to define a metering assembly, and wherein an
end of the
metering assembly can be attached to an electrical submersible pump. In an
example, a
power source is included that is in communication with the electrical
submersible pump.
Alternatively, a power cable provides electrical communication between the
power source
and the electrical submersible pump, and wherein signals between the first and
second
pressure sensors are transmitted to the controller along the power cable. In
an example, the
flow of fluid travels along a path that passes inside of the first and second
pipe sections.
Alternatively, the flow of fluid travels along a path that passes through an
annular space
between the first and second pipe sections and a sidewall of the well.
[0005] Also disclosed herein is another example of an apparatus for monitoring
a flow of
fluid in a subterranean well, and that includes an upper pipe section
selectively disposed in
the flow of fluid, an upper pressure sensor on the upper pipe section that
measures an upper
pressure loss of the flow of fluid along at least a portion of the upper pipe
section, the upper
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pressure loss made up of upper gravitational losses and upper frictional
losses, a lower pipe
section selectively disposed in the flow of fluid, a lower pressure sensor on
the lower pipe
section that measures a lower pressure loss of the flow of fluid along at
least a portion of the
lower pipe section, the lower pressure loss made up of lower gravitational
losses and lower
frictional losses, the lower pipe section having an outer diameter that is
less than an outer
diameter of the upper pipe section so that the lower frictional losses are
negligible with
respect to the lower gravitational losses, and a controller in communication
with the upper
and lower pressure sensors and that calculates a flowrate of the flow of fluid
based on upper
and lower gravitational losses, upper frictional losses, and that ignores the
lower frictional
losses. In an example, the upper pipe sections, the lower pipe sections, the
upper pressure
sensor, and the lower pressure sensor define a metering assembly. In one
alternative, an end
of the metering assembly is coupled to an electrical submersible pump that
pressurizes fluid
from the flow of fluid, and wherein the flowrate calculated by the controller
is substantially
the same as a flowrate of a flow of fluid that is being pressurized by the
electrical
submersible pump. In one embodiment, the upper pressure sensor includes
pressure sensors
that are axially spaced apart on the upper pipe section. The lower pressure
sensor can
include pressure sensors that are axially spaced apart on the lower pipe
section. In an
example, the controller estimates a pressure gradient ("PG") along a portion
of the lower pipe
section with the equation: PG = (g)(pm)/((ge)(144)). The controller can
estimate a water cut
percentage of the flow of fluid based on the equation. In an alternate
example, the controller
estimates the flowrate of the flow of fluid based on a relationship where a
pressure gradient
difference between the upper and lower pipe sections is: (fpniv2,i)/(24g,Dh).
A production
string can be included that is in fluid communication with the upper and lower
pipe sections.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0006] So that the manner in which the above-recited features, aspects and
advantages of the
invention, as well as others that will become apparent, are attained and can
be understood in
detail, a more particular description of the invention briefly summarized
above may be had
by reference to the embodiments thereof that are illustrated in the drawings
that form a part of
this specification. It is to be noted, however, that the appended drawings
illustrate only
preferred embodiments of the invention and are, therefore, not to be
considered limiting of
the invention's scope, for the invention may admit to other equally effective
embodiments.
[0007] Figure 1 is an elevational view of an electrical submersible pump with
a flow meter of
an embodiment of the current application.
[0008] Figure 2 is an elevational view of an electrical submersible pump with
a flow meter of
an alternative embodiment of the current application.
[0009] Figure 3 is a side sectional view of an alternate embodiment of the
electrical
submersible pump and flow meter of Figure 1.
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DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENTS
[0010] The method and system of the present disclosure will now be described
more fully
hereinafter with reference to the accompanying drawings in which embodiments
are shown.
The method and system of the present disclosure may be in many different forms
and should
not be construed as limited to the illustrated embodiments set forth herein;
rather, these
embodiments are provided so that this disclosure will be thorough and
complete, and will
fully convey its scope to those skilled in the art. Like numbers refer to like
elements
throughout. In an embodiment, usage of the term "about" includes +/- 5% of the
cited
magnitude. In an embodiment, usage of the term "substantially" includes +/- 5%
of the cited
magnitude.
[0011] It is to be further understood that the scope of the present disclosure
is not limited to
the exact details of construction, operation, exact materials, or embodiments
shown and
described, as modifications and equivalents will be apparent to one skilled in
the art. In the
drawings and specification, there have been disclosed illustrative embodiments
and, although
specific terms are employed, they are used in a generic and descriptive sense
only and not for
the purpose of limitation.
[0012] Shown in a side sectional view in Figure 1 is an example of a well 10
having one
embodiment of an electric submersible pump ("ESP") 12 disposed therein. As
shown, ESP
12 depends from an end of a tubing string 14 disposed in the well 10. In the
illustrated
example, well 10 has in internal bore 11 with a diameter 13. Included with the
example of
the ESP 12 is an electric motor 16 with a seal section 18 disposed adjacent
motor 16. In an
example, seal section 18 equalizes pressure within ESP 12 with ambient
pressure to reduce
pressure differentials on fluid seals in the ESP 12 and thereby prevent well
fluid from
entering motor 16. ESP 12 also includes a pump section comprising pump
assembly 20
located on an end of seal section 18 distal from motor 16. Examples exist
where the pump
assembly 20 includes a pump such as a centrifugal pump. Pump assembly 20 could
alternatively include a progressing cavity pump, which has a helical rotor
that rotates within
an elastomeric stator. An ESP monitoring tool 22 is located below electric
motor 16. In the
illustrated example, monitoring tool 22 monitors various pressures,
temperatures, and
vibrations associated with the ESP 12. In the example of Figure 1, ESP 12
lifts well fluids
from within the well 10 to the surface. Fluid inlets 24 located on pump
assembly 20 define
an entryway for fluid to enter into ESP 12.
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[0013] In the embodiment of Figure 1, a power cable 26 extends alongside
production tubing
14, terminating in a splice or connector 28 that electrically couples cable 26
to a second
power cable, or motor lead 30. An end of motor lead 30 distal from power cable
26 connects
to a pothead connector 32 that electrically connects and secures motor lead 30
to electric
motor 16. Coupled with ESP 12 on an end distal from tubing string 14 is an
example of a
metering assembly 34. Metering assembly 34 includes an upper pipe section 36
shown
mounted to monitoring tool 22 of ESP 12. In the illustrated example, upper
pipe section 36 is
an elongated member having a curved outer periphery thereby having a cylinder
like outer
surface. Upper pipe section 36 has an external diameter 38. Metering assembly
34 also
includes a lower pipe section 40 located on a side of upper pipe section 36
distal from motor
16. Lower pipe section 40 is also elongated with a curved outer periphery to
have a generally
cylindrically shaped outer surface. External diameter 42 of lower pipe section
40 has a
magnitude less than that of the external diameter 38 of upper pipe section 36.
A tapered
intermediate pipe section 44 mates the upper pipe section 36 to lower pipe
section 40. The
intermediate pipe section 44 is tapered or swaged in such a manner to create a
smooth
transition between larger diameter upper pipe section 36 to the smaller
diameter lower pipe
section 40 to minimize the sudden flow disturbance and pressure losses within
bore 11.
[0014] As an example, each of upper pipe section 36 and lower pipe section 40
may have a
length of 15 to 20 feet. For a metering assembly 34 deployed inside a well 10
with an
internal diameter of 7 inches, which may be, for example, the internal
diameter of the casing
completion, the external diameter 42 of lower pipe section 40 may be 3.5
inches or smaller
and the external diameter 38 of upper pipe section 36 my be 5.5 inches. As a
second example,
for a metering assembly 34 deployed inside a well 10 with an internal diameter
of 9 5/8
inches, which may be, for example, the internal diameter of the casing
completion, the
external diameter 42 of lower pipe section 40 may be 4.5 inches or smaller and
the external
diameter 38 of upper pipe section 36 my be 7 inches.
[0015] As described, the external diameters 38, 42 of upper and lower pipe
sections 36, 40
are smaller than the internal diameter 13 of the bore 11 of well 10. The
annular spaces
between external diameters 38, 42 and bore 11 create an annular flow path 46
for the passage
of fluids within the well 10 as the fluid flows towards fluid inlets 24 of
pump assembly 20. A
pressure sensing means is located on upper pipe section 36 and lower pipe
section 40. In the
illustrated example, the upper pressure sensing means includes two upper flow
pressure
sensors 48, 50 located on upper pipe section 36. The upper sensors 48, 50 as
shown are
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located at an upper distance 52 apart from each other and selectively collect
data from fluid
flowing exterior to the upper and lower pipe sections 36, 40 in the annular
flow path 46.
Embodiments exist where upper distance 52 ranges from around 10 to 15 feet,
and all
distances within this range. Alternatively, a single pressure differential
sensor may be used to
measure the pressure difference between the two upper locations. As
illustrated, the lower
pressure sensing means includes two lower flow pressure sensors 54, 56 located
on lower
pipe section 40. The lower sensors 54, 56 are located at a lower distance 58
apart from each
other. In one example lower distance 58 ranges from around 10 feet to around
15 feet, and all
distances within this range. In an alternative, a single pressure differential
sensor is used to
measure the pressure difference between the two lower locations.
[0016] Because of the differences in the outer diameter 38 of upper pipe
section of upper
pipe section 36 and outer diameter 42 of lower pipe section 40, two
distinctive flow regimes
are created along the annulus flow path 46. One distinctive flow regime
extends along lower
distance 58 and another distinctive flow regime extends along upper distance
52. In a non-
limiting example of operation, a first pressure loss is measured over lower
distance 58. In
this example, the first pressure loss is determined by measuring a pressure
with first lower
sensor 56 and second lower sensor 54 and finding the difference between the
two pressure
readings. Alternatively, a single pressure differential sensor measures the
first pressure loss.
While the first pressure loss includes both gravitational and frictional
losses, the gravitational
losses exceed the frictional losses by an amount such that a sufficiently
accurate estimate of
the first pressure loss is calculated by ignoring the frictional losses. For
the purposes of
discussion herein, an example of a sufficiently accurate estimate includes
calculation results
that are within a margin of error so that a difference between calculations or
other evaluations
using the sufficiently accurate estimate are within an acceptable margin from
calculations that
account for the frictional losses. In one example, an acceptable margin would
mean that a
calculated size of something being designed to accommodate the flow fluid is
substantially
the same when accounting for frictional losses or not accounting for
frictional losses. As
such, in an example of evaluating the first pressure loss the frictional
losses between sensors
54, 56 are ignored and only the gravitational losses considered.
[0017] In one non-limiting example of operation the second pressure loss is
determined by
measuring a pressure in the fluid with first upper sensor 50 and second upper
sensor 48 and
finding the difference between the two pressure readings. In an alternative a
single pressure
differential sensor measures the second pressure loss. Because of the
relatively larger
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external diameter 38 of upper pipe section 36, the second pressure loss is
made up of
substantial amounts of both gravitational loss and frictional loss, so that an
accurate estimate
of the second pressure includes both gravitational and frictional pressure
losses. In the
illustrated example, the pressure loss data collected by sensors 48, 50, 54,
and 56 is
transmitted to surface along the power cable 26, which is in communication
with the
metering assembly 34 through ESP monitoring tool 22. In an embodiment, the
flow rate of
the fluids within well 10 and the water cut of such fluids is calculated with
this pressure loss
data using hydraulic equations as further describe herein. More specifically
in this example,
the first pressure loss estimated via the first and second lower sensors 56,
54 (or with a single
pressure differential sensor) is used to calculate oil-water mixture density
and the production
water cut. Further in this example, the second pressure loss, calculated with
data from first
upper sensor 50 and second upper sensor 48 (or with a single pressure
differential sensor) is
used to calculate oil-water mixture flowrate.
[0018] Referring now to Figure 2, shown in a side partial sectional view is an
alternate
embodiment of ESP 12 having an electric motor 16, seal section 18 adjacent
motor 16, and
pump assembly 20 on a side of seal section 18 distal from motor 16. In this
example
metering assembly 34 is disposed adjacent a side of pump assembly 20 distal
from seal
section 18 with lower pipe section 40 mounted to a discharge end of pump
assembly 20. ESP
monitoring tool 22 is shown adjacent electric motor 16 and distal from seal
section 18. Fluid
inlets 24 on pump assembly 20 define a passage for receiving fluid into ESP
12. The fluids
then continue upwards within lower pipe section 40 and upper pipe section 36,
and then
discharged into tubing string 14, where tubing string couples to an end of
upper pipe section
36 distal from lower pipe section 40. As shown, lower pipe section 40 has an
internal
diameter 42 which is smaller than the internal diameter 38 of upper pipe
section 36. A
tapered intermediate pipe section 44 mates the upper pipe section 36 to lower
pipe section 40.
The intermediate pipe section 44 is tapered in such a manner to create a
smooth transition
between upper pipe section 36 to lower pipe section 40 to minimize the sudden
flow
disturbance and pressure losses in fluid flowing along this flow path.
[0019] As an example, each of upper pipe section 36 and lower pipe section 40
have lengths
that range from about 15 feet to about to 20 feet, and all distances within
this range. For a
metering assembly 34 deployed inside a well 10 with an internal diameter of 7
inches, which
may be, for example, the internal diameter of the casing completion, the
internal diameter 42
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of lower pipe section 40 ranges up to about 3.5 inches, and the internal
diameter 38 of upper
pipe section 36 ranges up to about 5.5 inches.
[0020] As described, the internal diameters 38, 42 of upper and lower pipe
sections 36, 40 are
smaller than the internal diameter 13 of the bore 11 of well 10. An example of
a packer 60 is
depicted sealingly engaged between upper pipe section 36 and the bore 11.
Packer 60 blocks
flow path 46 so that fluids are diverted into fluid inlets 24, to be pressured
by pump assembly
20 and then transported to the surface through tubing string 14.
[0021] Examples of a upper and lower pressure sensing means are located on
upper pipe
section 36 and lower pipe section 40. The upper pressure sensing means as
shown includes
two upper flow pressure sensors 48, 50 located on upper pipe section 36. The
upper sensors
48, 50 are located at an upper distance 52 apart from each other. In an
embodiment, upper
distance 52 ranges from about 10 feet to about 15 feet, and all distances
within this range.
Alternatively, a single pressure differential sensor measures the pressure
difference between
the two upper locations. The lower pressure sensing means is illustrated as
having two lower
flow pressure sensors 54, 56 located on lower pipe section 40. The lower
sensors 54, 56 are
located at a lower distance 58 apart from each other. Lower distance 58
optionally ranges
from about 10 feet to about 15 feet, and all distances within this range.
Alternatively, a single
pressure differential sensor measures the pressure difference between the two
lower locations.
The sensor means of Figure 2 selectively collects data from fluid flowing
inside of lower pipe
section 40 and upper pipe section 36
[0022] Because of the differences in the inner diameter 38 of upper pipe
section 36 and inner
diameter 42 of lower pipe section 40, two distinctive flow regimes are
created, one along
lower distance 58 and another along upper distance 52. In one non-limiting
example, a
pressure loss is measured over lower distance 58. The pressure loss is
determined by
measuring a pressure with first lower sensor 56 and second lower sensor 54 and
finding the
difference between the two pressure readings. Alternatively, a single pressure
differential
sensor can measure the pressure loss. Because of the relatively smaller
internal diameter 42
of lower pipe section 40, gravitational losses and friction losses both
significantly contribute
to the pressure loss so that a precise estimate of the pressure loss requires
that each of these
types of losses be considered and neither can be ignored.
[0023] Further in this example, another pressure loss is measured over upper
distance 52.
This pressure loss is determined by measuring a pressure with first upper
sensor 50 and
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second upper sensor 48 and finding the difference between the two pressure
readings.
Alternatively, a single pressure differential sensor can measure this pressure
loss. Because of
the relatively larger internal diameter 38 of upper pipe section 36 and lower
flow velocity in
this region, gravitational losses of the fluid between the first and second
upper sensors 50, 48
are the primary losses contributing to this pressure loss. Accordingly, a
precise value of
pressure losses in the fluid flowing between the first and second upper
sensors 50, 48 can be
estimated by ignoring the frictional losses of the fluid flowing in this
region.
[0024] In a non-limiting example of operation, pressure loss data collected by
sensors 48, 50,
54, and 56 is transmitted to surface for evaluation. In an alternative, the
data is transmitted
along power cable 26 (Figure 1), which is in communication with metering
assembly 34
through the ESP monitoring tool 22. Further in this example, the flow rate of
the fluids
within well 10, the fluid density, and the water cut of such fluids is
calculated with this
pressure loss data using hydraulic equations as further described herein. More
specifically,
the first pressure loss is calculated with data from the first upper sensor 48
and second upper
sensor 50 (or with a single pressure differential sensor), the first pressure
loss is also used to
calculate oil-water mixture density and the production water cut. The second
pressure loss is
calculated with data from first lower sensor 54 and second lower sensor 56 (or
with a single
pressure differential sensor) is used to calculate oil-water mixture flowrate.
[0025] In the embodiment of Figure 1, the water cut is calculated by first
finding the pressure
gradient (psi/ft) over lower distance 58, i.e. DPilLi. As the gravitational
loss is the major
contributor to pressure loss over lower distance 58, in an example embodiment
the frictional
loss is ignored when estimating this pressure gradient. Ignoring frictional
loss results in a
relationship for pressure gradient that is illustrated by Equation 1 below:
PG = (g)(p.)/((gc)(144)) Equation 1
[0026] Where g is the gravitational acceleration, 32.2 ft/sec2, ge is a unit
conversion factor,
32.2 lbm-ft/lbf-sec2, and pm is the oil-water mixture density in lbm/ft3.
After determining pm
from Equation 1, production water cut can be calculated. A similar analysis
could be
performed over upper distance 52 of the embodiment of Figure 2 because this
pressure loss is
affected primarily by gravitational loss such that the frictional losses of
fluid flowing in this
region are sufficiently negligible that they can be ignored without impacting
the precision of
the resulting calculation.
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[0027] Returning to the embodiment of Figure 1, a pressure gradient (psi/ft)
over upper
distance 52 is estimated and expressed as DP2/L2. Here, the respective values
of gravitational
losses and frictional losses have magnitudes that are sufficiently high in
relation to one
another so that ignoring either the gravitational or frictional loss would
produce inaccurate
hydraulic calculations for the fluid flowing along upper distance 52. For this
region of fluid
flow the frictional pressure gradient results in the relationship of Equation
2 below:
PG2 ¨ PG2 = (fp.v2m)/(24g,Dh) Equation 2
[0028] Where vni is the oil-water mixture velocity in ft/sec in upper distance
52, Ph is the
hydraulic diameter for the annulus in inches, calculated as internal diameter
13 minus
external diameter 38, and f is the friction factor. A similar analysis would
also apply to the
lower distance 58 of the embodiment of Figure 2 where the pressure loss is
dominated by
both gravitational and friction losses.
[0029] The friction factor is a function of Reynolds number and roughness, and
can be
determined from Moody's chart or empirical correlations. Equation 2 can be
used iteratively
to obtain the mixture velocity and the total oil-water flowrate. With water
cut calculated
previously, the individual oil and water rates can be easily calculated.
[0030] Referring now to Figure 3, shown in a side sectional view is an
alternate example of
the ESP 12A and metering assembly 34A of Figure 1. As shown, an end of the
tubing 14A
distal from pump assembly 20A couples with a wellhead assembly 70A shown
mounted on
surface 71A and above an opening of the well 10A. In the illustrated example,
fluid F flows
into well 10A from perforations 72A that project radially outward from well
10A. The
perforations 72A extend through casing 74A that lines the well 10A, and into
formation 76A
that surrounds well 10A. The fluid F produced from the formation 76A is
pressurized in
pump assembly 20A after being drawn into pump assembly 20A via fluid inlets
24A. The
pressurized fluid is discharged into the tubing string 14A and routed to the
wellhead assembly
70A for distribution to storage and/or process facilities (not shown). Further
illustrated in
Figure 3 is the power cable 26A extending generally parallel with the tubing
14A between the
motor lead 30A and the wellhead assembly 70A. At the wellhead assembly 70A,
the power
cable 26A is routed through a passage 78A, which has an end that intersects a
surface of the
wellhead assembly 70A that faces the well 10A. An opposite end of the passage
78A
intersects a surface of wellhead assembly 70A outside of the well 10A and
above surface
71A. After exiting the end of the passage 78A above surface 71A, the power
cable 26A
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connects to a power supply 80A shown on surface 71A. Examples of the power
supply 80A
include an electrical grid, a transformer, a generator, any other means of
providing electricity,
and combinations thereof. Electricity from the power supply 80A is selectively
conducted
via power cable 26A to ESP 12A for powering pump assembly 20A. Optionally, a
variable
frequency generator and controls (not shown) are included in the power supply
80A.
[0031] Further in the example of Figure 3, pressure transmitters 82A14 are
shown connected
respectfully to pressure sensors 48A, 50A, MA, 56A. Here, pressure
transmitters 821_4 send
signals to a controller 84A shown on surface 71A and outside of well 10A,
where the signals
communicated by pressure transmitters 821_4 represent ambient conditions of
fluid F in the
well 10A that are sensed by pressure sensors 48A, 50A, MA, 56A. In an example,
the
controller 84A includes an information handling system ("IHS"); embodiments
exist where
the IHS includes a processor, memory accessible by the processor, nonvolatile
storage area
accessible by the processor, and logics for performing each of the steps above
described.
Controller 84A receives the signals and translates the signals into a form,
such as data or
information, that is recognizable by the controller 84A, and performs
operations based on the
recognized data/information. In an
example, the controller 84A recognizes the
data/information as having a magnitude or value and calculates results based
on the
magnitude/value.
[0032] In one example of the system illustrated in Figure 3, communication
links 86A14
connect to and provide communication between the pressure transmitters 82A14
and the
controller 84A, and which provide a way for the signals sent by the pressure
transmitters
82A14 to be delivered to the controller 84A. Optionally, the communication
links 86A14 are
formed from a signal transmission medium, such as a conductive metal,
composites, fiber
optics, and combinations thereof. In an embodiment, the communication links
86A14 include
waves, such as radio waves, light waves, and other electromagnetic waves,
sonic waves,
acoustic waves, and combinations thereof. While the communication links 86A14
are
illustrated as following a dedicated path separate from the motor lead 30A and
power cable
26A, in one example communication links 86A14 are included within the motor
lead 30A
and/or power cable 26A. Optionally, the signals communicated between sensors
48A, 50A,
MA, 56A, pressure transmitters 82A14, and controller 84A are transmitted via
the motor lead
30A and/or power cable 26A.
[0033] Further in the example of Figure 3, as the fluid F flows past the
sensors 48A, 50A,
MA, 56A, pressure of the fluid F adjacent the sensors 48A, 50A, MA, 56A is
monitored by
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the sensors 48A, 50A, MA, 56A. Signals are generated and sent to the
controller 84A from
the sensors 48A, 50A, MA, 56A along the pressure transmitters 82A14 and
communication
links 86A14. In one non-limiting example of operation, at least one or more of
a flow rate of
the flow of fluid F, water cut, production cut, and fluid density is estimated
by the controller
84A. Optionally, operation of the controller 84A is in accordance with the
relationships of
Equations 1 and 2, and per the steps described above. In an example, these
values estimated
by the controller 84A are based on pressure differentials between the sensors
48A, 50A, MA,
56A.
[0034] Still referring to Figure 3, a passage 88A, similar to passage 78A, is
shown formed
through wellhead assembly 70A, and which provides a pathway for the placement
of
communication links 86A14 through the wellhead assembly 70A. A packer 90A is
also
illustrated that is sealingly disposed in the annular space between pump
assembly 20A and
inner surface of casing 74A and which blocks the flow of fluid F past ESP 12A
and forces the
fluid F into inlets 24A so that the fluid can be pressurized for transport to
the wellhead
assembly 70A.
[0035] Although the present invention has been described in detail, it should
be understood
that various changes, substitutions, and alterations can be made hereupon
without departing
from the principle and scope of the invention. Accordingly, the scope of the
present
invention should be determined by the following claims and their appropriate
legal
equivalents.
[0036] The singular forms "a", an and the include plural referents, unless the
context
clearly dictates otherwise. Optional or optionally means that the subsequently
described
event or circumstances may or may not occur. The description includes
instances where the
event or circumstance occurs and instances where it does not occur. Ranges may
be
expressed herein as from about one particular value, and/or to about another
particular value.
When such a range is expressed, it is to be understood that another embodiment
is from the
one particular value and/or to the other particular value, along with all
combinations within
said range.
[0037] Throughout this application, where patents or publications are
referenced, the
disclosures of these references in their entireties are intended to be
incorporated by reference
into this application, in order to more fully describe the state of the art to
which the invention
pertains, except when these reference contradict the statements made herein.
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CA 03043857 2019-05-14
WO 2018/089576
PCT/US2017/060768
[0038] The present invention described herein, therefore, is well adapted to
carry out the
objects and attain the ends and advantages mentioned, as well as others
inherent therein.
While a presently preferred embodiment of the invention has been given for
purposes of
disclosure, numerous changes exist in the details of procedures for
accomplishing the desired
results. These and other similar modifications will readily suggest themselves
to those skilled
in the art, and are intended to be encompassed within the spirit of the
present invention
disclosed herein and the scope of the appended claims.
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