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 device for measuring the flow rate of a fluid in a wellbore,
comprising: a variable orifice valve; and a differential pressure
measurement mechanism for measuring the pressure loss of the fluid
across the variable orifice valve.
2. The device of claim 1 wherein the variable orifice valve comprises
a sleeve valve.
3. The device of claim 2 wherein the variable orifice valve is
mounted on a side pocket mandrel.
4. The device of claim 1 wherein the variable orifice valve is
mounted on a side pocket mandrel.
5. The device of claim 1 wherein the differential pressure measurement
mechanism comprises: an outer pressure measurement device for measuring
the pressure upstream of the variable orifice valve; and an inner
pressure measurement device for measuring the pressure downstream
of the variable orifice valve.
6. The device of claim 1 wherein the differential pressure measurement
mechanism comprises a differential pressure measurement device for
measuring both the pressure downstream and upstream of the variable
orifice valve.
7. The device of claim 1 wherein: the variable orifice valve is
adapted to allow flow of the fluid from an annulus of the wellbore
to the interior of a tubing string disposed in the wellbore; and
the differential pressure measurement mechanism measures the pressure
of the fluid in the annulus and in the tubing string interior.
8. The device of claim 1 wherein the fluid is a singe phase liquid.
9. The device of claim 1 wherein the fluid is a single phase gas.
10. The device of claim 1 wherein the fluid includes a water and
an oil content.
11. The device of claim 1 wherein the fluid is a two phase liquid
and gas flow.
12. The device of claim 1 wherein the fluid is a multi phase flow.
Description [0001] This application is a divisional of U.S. application Ser.
No. 09/672471 filed on Sep. 28 2000 which claims priority under
35 USC 119(e) to U.S. Provisional Application Serial No. 60/195831
filed on Apr. 11 2000.
BACKGROUND
[0002] 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.
[0003] 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.
[0004] 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.
[0005] 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
[0006] 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
[0007] FIG. 1 is a view of a wellbore having multiple zones with
a flow meter disposed for each zone.
[0008] FIG. 2 is a cross-sectional view of the flow meter.
DETAILED DESCRIPTION
[0009] 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.
[0010] 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.
[0011] A. Flow Meter
[0012] 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.
[0013] 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.
[0014] 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.
[0015] 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 Schlumberger'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.
[0016] 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.
[0017] 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.
[0018] B. Liquid Flow Rate Equation
[0019] 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: 1 Q = C A 2 P
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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]:
A=n.sub.oa
[0025] 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.
[0026] 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]:
a=f.sub.a(h).apprxeq.yh.sup..alpha., .alpha.>0
[0027] 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:
2 a a 0 = x h z ( v + ( 1 - v ) x h 2 z )
[0028] where a.sub.0 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.
[0029] The remaining parameter required to determine flow rate
using Equation [1] is the flow coefficient (C), which is dependent
on the following parameters: 3 C = C f ( Re , A u a , A d a , pressure
tap locations )
[0030] 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).
[0031] 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.
[0032] 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).
[0033] 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).
[0034] C. Flow Rate Calculation
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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].
[0039] 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.
[0040] D. Gas Flow Rate Equation and Calculation
[0041] 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.
[0042] 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.
[0043] E. Oil/Water Flow Rate Equation and Calculation
[0044] 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 (.rho..sub.e),
in turn, can be calculated by the following Equation [5]:
.rho..sub.e=.rho..sub.wS.sub.w+.rho..sub.o(1-S.sub.w)
[0045] 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:
q.sub.w=qS.sub.w and q.sub.o=q(1-S.sub.w)
[0046] 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.
[0047] F. Flow Rate Equation and Calculation for Other Phases
[0048] 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.
[0049] G. Subsequent Calibration
[0050] 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.
[0051] 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.
[0052] 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]: 4 Q = Cn 0 a 2 P
[0053] 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 (a) 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.
[0054] 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]: 5 Q = Cn 0 h 2 P
[0055] 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.
[0056] 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]: 6 Q = Cn 0 a 0 x h z v + ( 1 - v ) x h 2 z 2 P
[0057] 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.
[0058] 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.
[0059] 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.
[0060] 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. |