## Abstrict This invention comprises the use of a variable orifice valve as
a flow controller and flow meter. Pressure measurements are taken
upstream and downstream of the variable orifice valve by way of
a differential pressure measurement mechanism. The differential
pressure measurement mechanism may comprise two separate absolute
pressure measurement devices or a single differential pressure measurement
device. Flow rate through the valve is determined from the pressure
drop across the valve. In wellbores having multiple zones, a variable
orifice valve together with a differential pressure measurement
mechanism may be deployed for each zone. The flow rate through each
of the zones and at the surface can then be monitored and controlled.
## Claims We claim:
1. A method for measuring the flow rate of a fluid in a wellbore,
comprising: flowing the fluid through a variable orifice valve having
one or more orifices between an annular region outside a tool string
and a region inside the tool string; measuring the pressure differential
of the fluid across the variable orifice valve; and calculating
the flow rate through the variable orifice valve by use of the pressure
differential measurement.
2. The method of claim 1 further comprising: determining the flow
coefficient and the total area of the variable orifice valve openings
that are exposed to flow ("the total area"); determining
the expansibility factor and the fluid density of the fluid flowing
through the variable orifice valve; and calculating the flow rate
through the variable orifice valve by use of the pressure differential
measurement, the flow coefficient, the total area, the expansibility
factor, and the fluid density.
3. The method of claim 2 wherein the determining the expansibility
factor and the fluid density step comprises performing a PVT calculation
of the fluid.
4. The method of claim 2 wherein the determining the expansibility
factor and the fluid density step comprises determining the fluid
density by taking a gradiomanometer measurement of the fluid.
5. The method of claim 3 wherein the determining the expansibility
factor and the fluid density step further comprises approximating
the expansibility factor to equal 1.
6. The method of claim 1 wherein the fluid is a singe phase liquid.
7. The method of claim 1 wherein the fluid is a single phase gas.
8. The method of claim 1 wherein the fluid includes a water and
an oil content.
9. The method of claim 2 wherein the fluid includes a water and
an oil content.
10. The method of claim 1 wherein the fluid is a two phase liquid
and gas flow.
11. The method of claim 1 wherein the fluid is a multi phase flow.
12. The method of claim 9 wherein the determining the expansibility
factor and the fluid density step comprises determining the fluid
density by utilizing the equation
to solve for .rho., wherein (S.sub.w) is the water holdup, (.rho..sub.w)
is the density of the water content in the flow, and (.rho..sub.o)
is the density of the oil content in the flow.
13. The method of claim 9 wherein the determining the expansibility
factor and the fluid density step comprises estimating the fluid
density by taking a differential pressure measurement along the
flowline downstream of the valve.
14. The method of claim 1 wherein the measuring the pressure differential
step comprises measuring the pressure upstream of the variable orifice
valve with an outer pressure measurement device and measuring the
pressure downstream of the variable orifice valve with an inner
pressure measurement device.
15. The method of claim 1 wherein the measuring the pressure differential
step comprises measuring the pressure upstream and downstream of
the variable orifice valve with a differential pressure measurement
device.
16. The method of claim 1 further comprising: placing the variable
orifice valve in a side pocket of a side pocket mandrel.
17. The method of claim 16 wherein flowing the fluid through the
variable orifice valve comprises flowing the fluid through a valve
selected from the group consisting of a side pocket sleeve valve,
a disc valve, and a butterfly valve.
18. A method for measuring the flow rate of a fluid in a wellbore,
comprising: flowing the fluid through a variable orifice valve;
measuring the pressure differential of the fluid across the variable
orifice valve; determining the flow coefficient and the total area
of variable orifice valve openings that are exposed to flow; and
calculating the flow rate through the variable orifice valve by
use of the pressure differential measurement, the flow coefficient,
and the total area, wherein the determining the flow coefficient
and the total area step comprises determining the flow coefficient
and the total area for each setting of the variable orifice valve.
19. The method of claim 18 wherein the determining the flow coefficient
and the total area step comprises characterizing the total area
using the equation A=n.sub.o.alpha., wherein (A) equals the total
area, (n.sub.o) is the number of the valve openings that are exposed
to flow, and (.alpha.) is the area of each of the valve openings.
20. The method of claim 19 wherein the characterizing step further
comprises utilizing the equation .alpha.=.gamma.h.sup..alpha. to
solve for (.alpha.), wherein .gamma. and .alpha. are characterizing
parameters and h is a variable representing the stem position of
the valve for a given setting.
21. The method of claim 19 wherein the characterizing step further
comprises: utilizing the equation ##EQU7##
to solve for (.alpha.), wherein (.alpha..sub.o) is the area per
opening when the valve is in the fully open position, (X.sub.h)
is the fractional stem movement of the valve which equals h/h.sub.max
(with (h) being a variable representing the stem position of the
valve for a given setting), and v and z are characterizing parameters.
22. The method of claim 18 wherein the determining the flow coefficient
and the total area step comprises determining the flow coefficient
prior to deployment into the wellbore.
23. The method of claim 22 wherein the flow coefficient is determined
by connecting the variable orifice valve to a laboratory simulator
that simulates flow of downhole fluids.
24. The method of claim 18 wherein the determining the flow coefficient
and the total area step comprises determining the flow coefficient
while the valve is deployed in the wellbore.
25. The method of claim 24 wherein the flow coefficient is determined
by utilizing the equation ##EQU8##
to solve for (C), wherein (Q) is the flow rate, (C) is the flow
coefficient, (A) is the total area, (.epsilon.) is the expansibility
factor, (.DELTA.P) is the pressure drop across the valve, and (.rho.)
is the upstream fluid density.
26. A method for measuring the flow rate of a fluid in a wellbore,
comprising: flowing the fluid through a variable orifice valve;
measuring the pressure differential of the fluid across the variable
orifice valve; determining the flow coefficient and the total area
of variable orifice valve openings that are exposed to flow; calculating
the flow rate through the variable orifice valve by use of the pressure
differential measurement, the flow coefficient, and the total area;
and calibrating the flow coefficient and the total area, wherein
the calibrating step comprises calibrating the flow coefficient
and the total area for each setting of the variable orifice valve.
27. The method of claim 26 wherein the calibrating step comprises
calibrating the flow coefficient and the total area while the valve
is deployed in the wellbore.
28. The method of claim 27 wherein the calibrating step takes
place without shutting in the wellbore.
29. The method of claim 27 wherein the wellbore includes a plurality
of producing formations and the calibrating step comprises closing
each of the producing formations except for the producing formation
in fluid communication with the variable orifice valve.
30. A method for measuring the flow rate of a fluid in a wellbore,
comprising: flowing the fluid through a variable orifice valve;
measuring the pressure differential of the fluid across the variable
orifice valve; calculating the flow rate through the variable orifice
valve by use of the pressure differential measurement; determining
the flow coefficient and the total area of the variable orifice
valve openings that are exposed to flow ("the total area");
determining the expansibility factor and the fluid density of the
fluid flowing through the variable orifice valve; calculating the
flow rate through the variable orifice valve by use of the pressure
differential measurement, the flow coefficient, the total area,
the expansibility factor, and the fluid density; and calibrating
the flow coefficient and the total area, wherein the calibrating
step comprises calibrating the flow coefficient and the total area
for each setting of the variable orifice valve, and, wherein the
calibrating step comprises determining the product of the flow coefficient
and the total area by utilizing the equation ##EQU9##
to solve for (C), wherein (Q) is the flow rate, (C) is the flow
coefficient, (A) is the total area, (.epsilon.) is the expansibility
factor, (.DELTA.P) is the pressure drop across the valve, and (.rho.)
is the upstream fluid density.
31. A method for measuring the flow rate of a fluid in a wellbore,
comprising: flowing the fluid through plural variable orifice valves;
measuring the differential pressure of the fluid across each of
the variable orifice valves, and calculating flow rate in a tubing
string based on the differential pressure measurements across corresponding
variable orifice valves.
32. The method of claim 31 further comprising providing each variable
orifice valve in a side pocket of a respective side pocket mandrel.
## Description BACKGROUND
This invention relates generally to flow meters used in the downhole
environment. Specifically, this invention relates to downhole flow
meters that operate by measuring the pressure drop across a variable
orifice valve.
Downhole flow metering is an essential component of reservoir monitoring.
As the industry has moved toward permanent monitoring and control
in real time, flow rate, pressure, temperature, resistivity, and
watercut, among others, have become important components for assessing
well performance.
To measure flow rates, a variety of sensors either on a standalone
basis or in combination have been deployed. These include spinner
tools, venturis, gradiomanometers, electromagnetic, acoustic, tracer
detectors and gamma-ray sensors. However, these tools are expensive.
Permanent downhole deployment of these sensors, especially when
individual zone flow rates in multi-zone wells are desired, would
require a large monetary investment.
Flow rate measurements may be used for a variety of purposes. The
primary use is to help in quantifying produced fluids. In wellbores
having multiple completions with feedback control, it may be desirable
to set flow rates or pressure for the various zones so as to optimize
the productivity. It is then necessary to measure the flow or pressure
rate in each zone, compare them to a set point, and adjust the aperture
openings in the valves of each zone completion in order to maintain
flow rate or pressure as close to the desired value as possible.
SUMMARY
This invention comprises the use of a variable orifice valve as
a flow controller and flow meter. Pressure measurements are taken
upstream and downstream of the variable orifice valve (across the
valve) by way of a differential pressure measurement mechanism.
The differential pressure measurement mechanism may comprise two
separate absolute pressure measurement devices or a single differential
pressure measurement device. Flow rate through the valve is determined
from the pressure drop across the valve. In wellbores having multiple
zones, a variable orifice valve together with a differential pressure
measurement mechanism may be deployed for each zone. The flow rate
through each of the zones, in the completion tubing, and at the
surface can then be monitored and controlled.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a view of a wellbore having multiple zones with a flow
meter disposed for each zone.
FIG. 2 is a cross-sectional view of the flow meter.
DETAILED DESCRIPTION
FIG. 1 shows a wellbore 10 that may include a casing 12 or liner
80 and that includes a tubing string 14 disposed therein. An annulus
13 is defined exterior to the tubing string 14. FIG. 1 shows a plurality
of zones 90 included in the wellbore 10. A flow meter 15 is incorporated
into the tubing string 14 for each zone 90. Although FIG. 1 shows
a wellbore 10 that includes multiple zones 90 (each having its own
flow meter 15), it is understood that a single flow meter 15 may
be disposed in a wellbore having only one zone 90 or that a single
flow meter 15 may be disposed in a wellbore having multiple zones
90. It is also understood that a flow meter 15 may be disposed in
the lateral bores of wellbores.
Each flow meter 15 is preferably proximate a formation 90. Typically,
the wellbore 10 is perforated to provide fluid communication between
each formation 90 and the wellbore 10 through perforations 92. Packers
94 are normally used to isolate each formation 90. The fluid flowing
from a formation 90 and being measured by flow meter 15 may be in
any of various phases, including single phase liquid or gas, two
phase oil/water, two phase liquid/gas, or multi-phase.
A. Flow Meter
FIG. 2 shows the flow meter 15 in more detail. In general, the
flow meter 15 of this invention comprises a variable orifice valve
16 and a differential pressure measurement mechanism 18.
In the embodiment shown in FIG. 2 variable orifice valve 16 comprises
a side pocket sleeve valve 17. However, variable orifice valve 16
may also comprise other types of valves, such as disc valves and
butterfly valves. In one embodiment as shown in the Figures, variable
orifice valve 16 is installed in a side pocket mandrel. In other
embodiments (not shown), variable orifice valve 16 is a part of
the main bore of the tubing string 14.
Variable orifice valve 16 provides fluid communication between
the annulus 13 and the interior of the tubing string 14 through
at least one opening 19. Variable orifice valve 16 preferably includes
a plurality of settings between fully closed and fully open, each
setting exposing a different amount of surface area of the opening(s)
19 to flow and thus allowing a different flow volume through valve
16.
The differential pressure measurement mechanism 18 measures the
pressure drop across the variable orifice valve 16. In one embodiment
as shown in FIG. 2 the differential pressure measurement mechanism
18 comprises a differential pressure measurement device 23 located
so that it can measure the pressure within the bore 24 of the tubing
string 14 as well as within the annulus 13. Adequate differential
pressure measurement devices 23 include differential pressure gauges,
such as Schlumherger's gradiomanometer tool. In another embodiment
(not shown), the differential pressure measurement mechanism 18
comprises a separate outer pressure measurement device and inner
pressure measurement device, each comprising a measurement device
such as an absolute pressure gauge. The outer pressure measurement
device is located so that it measures the pressure within the annulus
13. Preferably, the outer pressure measurement device is located
within the annulus 13 proximate the variable orifice valve 16. The
inner pressure measurement device is located so that it measures
the pressure within the bore 24 of the tubing string 14. Preferably,
the inner pressure measurement device is located within the bore
24 of the tubing string 14 also proximate the variable orifice valve
16.
In one embodiment, each variable orifice valve 16 is controlled,
as shown in FIG. 2 by hydraulic pressure from the surface through
at least one hydraulic control line 30. In other embodiments (not
shown), each variable orifice valve 16 may be controlled by electrical
conduits, pressure pulse telemetry, acoustic telemetry, or electro-magnetic
telemetry.
In one embodiment, each differential pressure measurement mechanism
18 is powered by at least one electrical conduit 32 which may also
serve to transfer the readings of the mechanism 18 to the surface.
In other embodiments (not shown), each differential pressure measurement
mechanism 18 is powered by a battery located downhole, and the readings
may be transferred to the surface by way of electrical conduits,
pressure pulse telemetry, acoustic telemetry, or electromagnetic
telemetry.
B. Liquid Flow Rate Equation
The flow rate of a single phase liquid across each variable orifice
valve 16 can be determined by use of the following fluid dynamics
Equation [1] or an equivalent thereof: ##EQU1##
where Q=flow rate, C=flow coefficient (this variable depends on
a number of factors as will be explained herein), A=total area of
variable orifice valve openings 19 that are exposed to flow, .epsilon.=expansibility
factor, .DELTA.P=pressure drop, and .rho.=upstream fluid density.
To calculate flow rate (Q) using Equation [1], the pressure drop
(.DELTA.P) is measured from the downhole readings of the differential
pressure measurement mechanism 18 as previously described. For
single phase liquid flow, the expansibility factor (.epsilon.) can
be approximated to equal 1.
The fluid density (.rho.) can be determined based on the prevailing
P, T and the PVT properties of the fluid. In one embodiment, the
PVT calculation is performed by taking a relevant fluid sample downhole,
bringing the sample to the surface, and analyzing it. In another
embodiment, the relevant calculation is performed by flowing only
the flow meter 15 that includes the relevant variable orifice valve
16 taking a sample of the fluid at the surface, and analyzing the
sample at the surface. In yet another embodiment, the fluid density
(.rho.) can be obtained from a gradiomanometer measurement or other
density measuring devices, such as gamma densitiometers and capacitance/resistance
devices.
In one embodiment, the total area of exposed variable orifice valve
openings (A) is determined by measurement at the surface. As previously
stated, variable orifice valve 16 preferably includes more than
one position between fully opened and fully closed. The total area
of exposed variable orifice valve openings (A) should therefore
be determined for each position or setting.
For valves having openings 19 that are identical, the total area
of exposed variable orifice valve openings (A) can be represented
by the following Equation [2]:
where n.sub.o is the number of openings 19 that are exposed to
the flow, and a is the area of each opening 19.
For a given stem position h of valve 16 the area (a) of each opening
19 exposed to the flow may be stated as a general Equation [3]:
where .gamma. and .alpha. are characterizing parameters and h is
a variable representing the stem position of valve 16 for a given
setting. The stem position variable (h) is known from the level
of valve 16 actuation performed or from a position transducer mounted
on valve 16. In general, Equation [3] may drift with time due to
erosion. Unfortunately, the erosion process is not adequately captured
by parameters .gamma. and .alpha.. For example, erosion may affect
the fully opened or fully closed positions more than some intermediate
settings. Therefore, a more general monotonic function may be preferable.
A reasonable Equation [4] to use is: ##EQU2##
where a.sub.o is the area per opening when the valve 16 is in the
fully open position, X.sub.h is the fractional stem movement which
equals h/h.sub.max, and v and z are characterizing parameters.
The remaining parameter required to determine flow rate using Equation
[1] is the flow coefficient (C), which is dependent on the following
parameters: ##EQU3##
where Re is the Reynold's Number defined at a reliable position
(for example the throat), A.sub.u is the area upstream of valve
16 (the area exposed to the formation), and A.sub.d is the area
downstream of valve 16 (approximately equal to the cross-sectional
area of the tubing string bore 24).
Since the flow coefficient (C) cannot be calculated with any certainty
using equations, it must be determined through experimentation and/or
mathematical modeling. The flow coefficient must be determined for
each setting of valve 16. The flow coefficient (C) can be experimentally
determined when the flow meter 15 is already downhole or prior to
downhole deployment of the flow meter 15.
To conduct the experiment when the flow meter 15 is already in
the downhole environment, the variable orifice valve 16 of the relevant
flow meter 15 is opened to one of its settings thus allowing flow
of fluids through the variable orifice valve 16 within tubing string
14 and to the surface. If more than one flow meter 15 is included
in the wellbore, only the variable orifice valve 16 of the flow
meter 15 being characterized is opened. The flow rate (Q) of the
fluid is then measured at the surface or by an independent flow
metering device downstream (e.g. spinner, etc.). Knowing the values
of all the relevant variables of Equation [1], Equation [1] is solved
for the flow coefficient (C). This procedure is repeated for each
setting of valve 16 (and for each valve 16).
To conduct the experiment prior to the downhole deployment of the
flow meter 15 the flow meter 15 is connected to a laboratory simulator
or a flow loop, wherein the flow of fluids through the variable
orifice valve 16 is simulated. All of the relevant variables of
Equation [1] will be known or measurable, including the flow rate
(Q). Knowing the values of all the relevant variables of Equation
[1], Equation [1] is solved for the flow coefficient (C). This procedure
is repeated for each setting of valve 16 (and for each valve 16).
C. Flow Rate Calculation
In general, formation fluid flows from a formation 90 through
perforations 92 into the annulus 13 through the variable orifice
valve 16 (at a specified setting), and into the bore 24 of the tubing
string 14. The fluid then flows within bore 24 to the surface of
the wellbore 10.
The calculation of flow rate across a single flow meter 15 disposed
in a flowing wellbore 10 is straight forward. Essentially, the pressure
readings from the differential pressure measurement mechanism 18
are taken real-time or at designated intervals and are transmitted
to the surface. The flow coefficient (C), total area of variable
orifice valve openings 19 that are exposed to flow (A), expansibility
factor (.epsilon.), and upstream fluid density (.rho.) are each
determined by the methods previously stated. It is noted that the
flow coefficient (C) and the total area of variable orifice valve
openings 19 exposed to flow (A) are different for each setting of
valve 16. Knowing each of these variables, Equation [1] can then
be easily applied to get the flow rate (Q) through the valve.
In one embodiment, the pressure readings from the differential
pressure measurement mechanism 18 are transmitted to a surface processor,
such as a computer. The surface processor also stores Equation [1]
and its relevant other variables and can thus calculate the flow
rate through the relevant valve 16 by using Equation [1], as previously
disclosed.
In another embodiment, the pressure readings from the differential
pressure measurement mechanism 18 are recorded within a recorder
deployed downhole. The readings may be subsequently retrieved to
the surface and plugged into Equation [1].
In those embodiments including more than one flow meter 15 such
as that shown in FIG. 1 the pressure downstream of each valve 16
is related to the flow entering through the valve 16 and the main
flow passing through the tubing string 14. Thus the downstream pressure
at each valve 16 controls both the flow through the valve 16 and
the total flow up to that point in the tubing string 14. Consequently,
the flow through each valve 16 is intimately related to the others.
Preferably, a mathematical flow model of the whole wellbore 10 is
designed, incorporating the required flow rates, formation pressures,
valve settings, well head pressure, valve losses and pipe losses.
This model is utilized to predict the flow rate and the pressure
throughout the wellbore 10.
D. Gas Flow Rate Equation and Calculation
The flow rate of a single phase gas flow across each variable orifice
valve 16 can also be determined by use of Equation [1] or an equivalent
thereof. However, unlike the calculation for single phase liquid
flow wherein the expansibility factor (.epsilon.) can be approximated
to equal 1 the expansibility factor (.epsilon.) for single phase
gas flow cannot be approximated and must be determined. For single
phase gas flow, the expansibility factor (.epsilon.) is determined
based on the prevailing P, T and the PVT properties of the fluid.
In one embodiment, the PVT calculation is performed by taking a
relevant fluid sample downhole, bringing the sample to the surface,
and analyzing it. In another embodiment, the relevant calculation
is performed by flowing only the flow meter 15 that includes the
relevant variable orifice valve 16 taking a sample of the fluid
at the surface, and analyzing the sample at the surface.
The remainder of the flow rate calculation for single phase gas
flow is the same as the flow rate calculation for single phase liquid
flow, as detailed in Sections B and C herein.
E. Oil/Water Flow Rate Equation and Calculation
For flow having oil and water content, experiments have shown that
a few diameters downstream of a venturi flow meter, the flow is
well mixed, i.e., in water-oil flow, and that the slip velocity
is negligible compared to either phase velocity. The holdup is then
equal to the fractional flow of the phases. For the drop sizes of
the entrained phase, we are expected to have negligible pressure
difference between the phases. Therefore, substituting the average
density .rho..sub.e for .rho. in Equation [1] gives the flow rate
equation for oil/water flow. The average density (p.sub.e), in turn,
can be calculated by the following Equation [5]:
where S.sub.w is the water holdup (approximately equal to its flow
fraction), .rho..sub.w is the density of the water content in the
flow, and .rho..sub.o is the density of the oil content in the flow.
In one embodiment, the water content density (.rho..sub.w), the
oil content density (.rho..sub.o), and the water holdup (S.sub.w)
are calculated by techniques and tools known to the prior art. In
another embodiment, a differential pressure measurement along the
flowline downstream of the orifice can provide an estimate of the
average density (.rho..sub.e). The differential pressure measurement
can be obtained by use of standard production logging application
tools, such as Schlumberger's Gradio Venturi Meter tool or other
fluid density measuring devices, such as gamma densiotemeters and
capacitance/resistance devices. Then, the following Equations [6]
can be used as a simple first approximations of the oil content
flow rate and the water content flow rate:
The remainder of the flow rate calculation for flow that includes
oil and water content is the same as the flow rate calculation for
single phase liquid flow, as detailed in Sections B and C herein.
F. Flow Rate Equation and Calculation for Other Phases
For flow having other types of phasing, such as two phase liquid/gas
or multi-phase fluid, the flow rate across valve 16 can also be
determined by use of Equation [1] or an equivalent thereof. As previously
mentioned with respect to the fluid phases described in Sections
B-E herein, the variables of Equation [1], including the expansibility
factor (.epsilon.) and the density (.rho.) or equivalent density
(.rho..sub.e), can be determined using tables, known instruments,
and/or calibration. Once the variables of Equation [1] are determined
sing such methods for the relevant fluid, the remainder of the flow
rate calculation is the same as the flow rate calculations described
previously.
G. Subsequent Calibration
The total area of exposed variable orifice valve openings (A) and
the flow coefficient (C) are likely to vary over a period of time
due to erosion of the valve openings 19 among other things. Thus,
to maintain the reliability of the flow rate (Q) calculation, the
total area of exposed variable orifice valve openings (A) and the
flow coefficient (C) should be re-calibrated from time to time.
In order to re-calibrate such variables, the variable orifice valve
16 of the relevant flow meter 15 is opened and the surface flow
rate (Q) is measured. If the wellbore includes more than one flow
meter 15 only the variable orifice valve 16 of the relevant flow
meter 15 should be opened. All other valves 16 should remain closed.
If Equation [2] is used to calculate the total area of exposed
variable orifice valve openings (A) for the relevant variable orifice
valve 16 then Equations [1] and [2] can be combined into the following
Equation [6]: ##EQU4##
The variable orifice valve 16 is opened to each of its settings
and the surface flow rate (Q) is measured at each setting. Equation
[6] is then solved for the product of the flow coefficient (C) and
the area (.alpha.) of each opening 19 for each of the settings of
variable orifice valve 16 (note n.sub.o is a known variable). This
technique can also be used when, as in Equation [1], only the variable
(A) is used (instead of also using Equations [2], [3], or [4]),
wherein Equation [1] would be solved for the product of the flow
coefficient (C) and the total area of exposed variable orifice valve
openings (A) for each setting of valve 16.
If Equation [3] is used to calculate the total area of exposed
variable orifice valve openings (A) for the relevant variable orifice
valve 16 then Equations [1] and [3] can be combined into the following
Equation [7]: ##EQU5##
The variable orifice valve 16 is then opened to two distinct settings
and the surface flow rate (Q) is measured for each of the two settings.
With two Equations [7] (one for each setting), the desired parameters
C.gamma. and .alpha. can be calculated thus providing the re-calibrated
values.
If Equation [4] is used to calculate the total area of exposed
variable orifice valve openings (A) for the relevant variable orifice
valve 16 then Equations [1] and [4] can be combined into the following
Equation [8]: ##EQU6##
The variable orifice valve 16 is then opened to three distinct
settings and the surface flow rate (Q) is measured for each of the
three settings. With three Equations [8] (one for each setting),
the desired parameters C, z, and v can be calculated thus providing
the re-calibrated values.
In any case, a venturi may also be included in the tubing string
14 above all of the zones 90. The venturi measures the total flow
from all zones 90. By testing each zone 90 individually (as above),
the flow measured across each valve 16 may then be compared to the
theoretical flow and the venturi flow, which comparison (with the
aid of time lapse trending) would provide an indication of the performance
of the valve, including the effects of erosion or hysterisis.
In view of the foregoing it is evident that the present invention
is one well adapted to attain all of the objects and features hereinabove
set forth, together with other objects and features which are inherent
in the apparatus disclosed herein.
As will be readily apparent to those skilled in the art, the present
invention may easily be produced in other specific forms without
departing from its spirit or essential characteristics. The present
embodiment is, therefore, to be considered as merely illustrative
and not restrictive, the scope of the invention being indicated
by the claims rather than the foregoing description, and all changes
which come within the meaning and range of equivalence of the claims
are therefore intended to be embraced therein. |