lllllllllllllllllllllllllllllllllllllllllllllllllllllllllIlllllllllllllllll
`U5005224372A
`
`United States Patent
`
`[19]
`
`[11] Patent Number:
`
`5,224,372
`
`Kolpak
`
`[45] Date of Patent:
`
`Jul. 6, 1993
`
`[54] MULTI-PHASE FLUID FLOW
`MEASUREMENT
`
`[75]
`
`Inventor:
`
`Miroslav M. Kolpak, Plano, Tex.
`
`[73] Assignee:
`
`Atlantic Richfield Company, Los
`Angeles, Calif.
`
`[21] Appl.No.: 781,434
`
`[22] Filed:
`
`Oct. 23, 1991
`
`Related US. Application Data
`
`[63]
`
`Continuation-impart of Ser. No. 523,152, May 14,
`1990, Pat. No. 5,090,253.
`
`Int. c1: ............................................. com 33/00
`[51]
`[52] US. Cl. ................................ 73/19.03;73/19.10
`[58] Field ofSearch ........... 73/861.04, 861.37, 861.38,
`73/1901, 19.03, 19.05
`
`[56]
`
`References Cited
`U.S. PATENT DOCUMENTS
`
`................. 73/861.38 X
`3,927,565 12/1975 Pavlin et al.
`73/861.37 X
`4.096.745
`6/1978 Riukin et al.
`5.029.482 7/199l Liu et al.
`...................... 73/86l.O4 X
`
`Attorney, Agent, or Firm—Michael E. Martin
`
`[57]
`
`ABSTRACT
`
`Multiphase (gas and two liquid phases) fluid flow-
`streams are measured to determine the total flow rate,
`fluid density, the fraction of gas, and one liquid in the
`total liquid mixture by passing the flowstream through
`a Ceriolis flow meter (16, 40), a densimeter (12) and a
`meter (14) which measures the fraction of one liquid in
`the two liquid mixture. The total fluid flow rate may be
`measured by a single tube flow meter (40) having adja-
`cent loops which provide tube legs (49, 51) positioned
`adjacent each other and vibrated laterally at a predeter-
`mined frequency and amplitude while measuring pres—
`sures in the contraflowing streams in the adjacent tube
`legs. The density and gas fraction of the flowstream
`may be determined by vibrating a tube containing the
`flowstream over a range of frequencies and measuring
`the phase angle and amplitude of the fluctuating fluid
`pressures compared with acceleration of the tube to
`determine the sloshing natural frequency of the fluid
`mixture. The tube may be vibrated at a frequency far
`from the sloshing natural frequency of the fluid mixture
`to determine the fluid density.
`
`Primary Examiner—Herbert Goldstein
`
`12 Claims, 2 Drawing Sheets
`
`
`
`CONTROL AND
`RECORD CIRCUIT
`
`Micro Motion 1024
`
`1
`
`Micro Motion 1024
`
`

`

`US. Patent
`
`July 6, 1993
`
`Sheet 1 of 2
`
`5,224,372
`
`
`
`2
`
`

`

`US. Patent
`
`July 6, 1993
`
`Sheet 2 of 2
`
`5,224,372
`
`SPECTRUM
`ANALYSER
`
`
`
`3
`
`

`

`1
`
`5,224,372
`
`MULTI-PHASE FLUID FLOW MEASUREMENT
`
`CROSS REFERENCE TO RELATED
`APPLICATION
`
`This application is a continuation in part of applica-
`tion Ser. No. 07/523,152, filed May 14, 1990, now US.
`Pat. No. 5,090,253, the subject matter of which is incor-
`porated herein by reference.
`BACKGROUND OF THE INVENTION
`
`5
`
`10
`
`.
`1. Field of the Invention
`The present invention pertains to methods and appa-
`ratus for measuring multi-phase fluid flow such as mix-
`tures of oil, water and gas utilizing a densimeter, a two- 15
`phase flow meter based on microwave attenuation char-
`acteristics and a mass or volumetric flow meter such as
`a modified coriolis-type flow meter.
`2. Background of the Invention
`Various techniques and systems have been developed 20
`for measuring multi-phase fluid flow,
`in particular,
`three phase fluid flow comprising a mixture of oil, water
`and gas. My US. Pat. No. 4,852,395, assigned to the
`assignee of the present invention describes a system for
`measuring multiphase fluid flow wherein gas is sepa’- 25
`rated from a mixture of oil and water and the fractions
`of oil and water are then determined including measur-
`ing batch samples to correct for the residual gas con-
`tent. Although such a system has a high degree of accu-
`racy, it is relatively mechanically complex and requires 30
`a gas separator and gas flow meter.
`Mechanically simple flow meters are sought for many
`applications, particularly in applications for measuring
`the multiphase fluid emanating from oil and gas wells
`wherein essentially, mixtures of water, hydrocarbon 35
`liquids, such as crude oil; and gas are continually pro-
`duced in varying proportions of the total fluid flow-
`stream. The present invention provides new and unique
`methods for measuring multiphase fluid flow, particu-
`larly of the type above described, as well as improved 40
`apparatus for measuring such multiphase fluid flow,
`which overcomes some of the problems associated with
`prior art methods and systems.
`SUMMARY OF THE INVENTION
`
`45
`
`The present invention provides improved methods
`for measuring multiphase fluid flow, such as mixtures of
`oil, water and gas.
`In accordance with one aspect of the present inven-
`tion a method is provided for measuring the oil, water 50
`and gas flow rates of a multiphase fluid flowstream
`without completely separating any of the fluid fractions
`from the flowstream. A system for practicing the
`method includes a meter which measures the oil and
`water fractions of the flowstream, a densimeter and a 55
`coriolis type flow meter. The oil-water fraction or
`“watercut” meter may be one of several types but is
`preferably one based on microwave attenuation charac-
`teristics which vary with the fraction of oil and water,
`respectively. The coriolis type flow meter may be of the 60
`type described in co-pending US. patent application
`Ser. No. 07/523,152.
`In another system and method according to the in-
`vention, the fractional volumetric flow rates may be
`determined using only,
`in combination, the watercut 65
`meter and the modified coriolis type flow meter.
`The present invention still further provides unique
`methods and apparatus for determining the gas fraction
`
`2
`and density of a multiphase fluid mixture utilizing a
`single continuous tube type device which is vibrated
`substantially at the sloshing resonant frequency of the
`fluid mixture, or determining the density of a fluid mix-
`ture by vibrating the device at a frequency substantially
`away from the sloshing resonant frequency. Still fur-
`ther, there is provided a method and system utilizing a
`single continuous tube type flow meter with tube por-
`tions wherein the fluid flow at a predetermined point is
`in opposite directions and wherein the difference in
`fluid pressures at selected locations in the tube are mea-
`sured to determine mass flow rate.
`Those' skilled in the art will recognize the above-
`described advantages and superior features of the pres-
`ent
`invention together with other important aspects
`thereof upon reading the detailed description which
`follows in conjunction with the drawing.
`BRIEF DESCRIPTION OF THE DRAWING
`
`FIG. 1 is a schematic diagram illustrating one combi-
`nation of measurement devices used in conjunction with
`the methods of the present invention.
`FIG. 2 is a side elevation of a single continuous tube
`type flow measuring apparatus in accordance with the
`present invention;
`FIG. 3 is a top plan view of the apparatus shown in
`FIG. 2;
`FIG. 4 is a section view taken along the line 4—4 of
`FIG. 2 illustrating an arrangement which is used in
`conjunction with a method of the present invention;
`FIG. 5 is a section view taken along line 5—5 of FIG.
`2 and including a diagram illustrating some of the di-
`mensions used in accordance with the‘method of the
`present invention.
`DESCRIPTION OF PREFERRED
`EMBODIMENTS
`
`In the description which follows like parts are
`marked throughout the specification and drawing with
`the same reference numerals, respectively. The drawing
`figures are not to scale and certain features are shown in
`schematic form in the interest of clarity and concise-
`.ness. Referring to FIG. 1, there is illustrated a conduit
`10 which is operable to conduct a multiphase fluid flow-
`stream, such as might result from the production of
`crude oil from a well, and which typically includes a
`mixture of crude oil, water and gas. The systems and
`methods described herein are more accurate when the
`gas content of the fluid flowstream is less than about
`twenty percent (20%) of the total. Preliminary separa-
`tion of gas might be necessary in some situations in
`order to prepare the flowstream for measurements by
`the system of the present invention. In FIG. 1, four
`separate devices are shown interposed in the conduit 10
`and which devices may be used in certain combinations
`or alone to make certain measurements in accordance
`with the present invention. A densimeter 12 is inter-
`posed in the conduit 10 which may be of the so-called
`gamma ray type, for example. The densimeter 12 may
`be of a type commercially available, such as a model
`S-Series “Sensor Net” manufactured by TN Technolo-
`gies,‘Inc. of Round Rock, Tex. A second device shown
`interposed in the conduit 10 for receiving flow of fluid
`therethrough is a so-called “watercut" meter, generally
`designated by the numeral 14, and of the type which
`measures changes in microwave attenuation resulting
`from changes in the composition of the fluid flowing
`
`4
`
`

`

`.
`3
`therethrough. The meter 14 is preferably of the type
`disclosed and claimed in US. Pat. Nos. 4,862,060 issued
`Aug. 29, 1989 or 4,996,490 issued Feb. 26, 1991 both to
`Scott et al. and both assigned to the assignee of the
`present invention. Suffice it to say that the meter 14 is
`operable to measure the water fraction of an oil-water
`mixture which may include certain amounts of gas en—
`trained therein.
`
`FIG. 1 further illustrates a modified coriolis type
`flow meter, generally designated by the numeral 16,
`which may be of the type described in application Ser.
`No. 07/523,152. Basically, the flow meter 16 comprises
`an inlet conduit 18 which is split into two branch con-
`duits 19 and 20 which are in communication with re-
`spective bundles of smaller diameter tubes 22 and 24,
`having a generally U-shaped configuration, and con-
`nected to an outlet manifold 26 similar to the manifold
`or conduit 18. The tube bundles 22 and 24 are vibrated
`in a generally lateral direction with respect to their
`longitudinal central axes by suitable vibrator means 28
`and the vibrations of the respective upstream and down-
`stream legs of the tube bundles 22 and 24 are sensed by
`vibration sensors 30 and 32. Further details of the flow
`meter 16 may be obtained by referring to the above-
`referenced patent application.
`In accordance with a first method the gas, water and
`oil flow rates in a multi-phase fluid flowstream flowing
`through the conduit 10 may be determined utilizing the
`densimeter 12, a meter such as the meter 14, and the
`coriolis flow meter 16, for example. The densimeter 12
`provides measurement of the total fluid mixture density,
`dm, and the coriolis flow meter 16 provides measure-
`ment of the apparent mixture density, dma, which is
`related to the true mixture density, dm, by the equation:
`
`dm=dma(l+A2’/g+A3’/g2)
`
`(1)
`
`where A2 and A3 are coefficients which may be deter-
`mined earlier by calibration of the meter 16 in gassy
`liquid flow wherein small uniformly distributed gas
`bubbles are present in the range of zero percent (0%) to
`twenty percent (20%) by volume in the liquid, and fg is
`the gas fraction of the multi-phase fluid flowstream.
`Equation (1) may be solved for the gas fraction, fg,
`which then takes the form:
`‘
`
`f8
`
`\r—-———-——,
`.42- — 4,4331 —— dm/dma)
`2A3
`
`(2)
`
`The coriolis type flow meter 16, is operable to pro-
`vide a measurement of the apparent mass flow rate of
`the fluid flowstream, Ma, which is related to the true
`mass flow rate, M, by the equation:
`
`M=Ma(l+A4‘fg+A5‘fg2+. . .)
`
`55
`
`(3)
`
`. are coefficients which are also deter-
`.
`where A4, A5, .
`mined earlier by calibration of the coriolis meter 16 in
`gassy liquid flow wherein small uniformly distributed
`gas bubbles are present in the range of zero percent
`(0%) to twenty percent (20%) by volume, in the liquid.
`The oil, water and gas volumetric flow rates Qo, Qw,
`and Qg are computed by:
`
`QO=QM(l-ngI—Wt)
`
`QW= QM l ~fg)‘ wt
`
`65
`
`(4)
`
`(5)
`
`5,224,372
`
`Qg=Qm ‘fg
`
`4
`
`(6)
`
`5
`
`10
`
`15
`
`20
`
`25
`
`30
`
`35
`
`40
`
`45
`
`50
`
`where Qm is the volumetric flow rate of the fluid mix-
`ture determined by:
`
`Qm=M/drn
`
`(7)
`
`where dm and M are computed by equations (1) and (3)
`substituting the value of the gas fraction, fg, determined
`in equation (2) and the value of the water fraction, wc,
`as determined by the meter 14. The method just de-
`scribed above provides volumetric flow rates for the oil
`fraction, the water fraction and the gas fraction without
`the need of knowing the density of each of these com- .
`ponents.
`in situations where the water
`On the other hand,
`density, the oil density and the gas density are known or
`are easily measured and are relatively stable from time
`to time over the period where flow measurement is
`desired, the flow rates of each of the fractions of gas,
`water and oil in the multi-phase flowstream may be
`determined by a second method using a watercut meter
`and a modified coriolis type meter such as the meters 14
`and 16, respectively. The coriolis meter 16 will provide
`a measurement of the apparent density of the mixture,
`dma, which may be used to determine the true density,
`dm, from equation (1). The gas fraction, fg, is related to
`the density values and the water fraction (on a volumet-
`ric basis) by the following equation:
`
`fg= [wc(dw—do)+(do—dm)]/{wc(dw—da)+ -
`(do—dg)l
`
`(8)
`
`where fg is the gas fraction, we is the water fraction
`measured by the meter 14, do is the oil density, dw is the
`water density and dg is the gas density.
`.
`Simultaneous solution of equations (1) and (8) yields
`
`_ db: — 4a:
`fg —
`2a
`
`where
`
`a=dma ‘A3
`
`b=dma‘A2+wc(dw—do)+(do—dg)
`
`c=dma—wc(dw—do)—do
`
`wc=measured by meter 14
`
`.
`
`dma=measured by coriolis meter 16
`
`(9)
`
`(10)
`
`(ll)
`
`do,dw,dg=known (measured) densities of oil, water
`and gas
`The oil, water and gas flow rates Qo, Qw, and Qg
`may then be computed using equations (4) through (6).
`Accordingly, a method utilizing only two meters,
`namely the meters 14 and 16 may be used if the densities
`of the fluid fractions can be measured and remain rela-
`tively constant.
`Inaccuracies caused by imprecise
`knowledge of the oil density and the water density
`when oil gravity is low (API gravity approaches about
`10) do not occur.
`In accordance with a third method of the present
`invention, the flow rates of the fractional fluid compo-
`nents of a multi-phase fluid flowstream flowing through
`the conduit 10 may be determined utilizing a watercut
`
`5
`
`

`

`5,224,372
`
`5
`meter such as the meter 14, a flow meter such as the
`modified coriolis meter 16 or a flow meter 36 and an
`apparatus such as the type described in FIGS. 2 through
`5.
`
`Referring now to FIGS. 2 through 5 there is illus-
`trated an apparatus for use in measuring the flow rate of
`a multiphase fluid stream including a mixture of gas and
`liquid. The apparatus illustrated is generally designated
`by the numeral 40 and is characterized by a continuous
`double loop of tubing or conduit 42 having an inlet end
`44 and a discharge end 46. The conduit 42 includes two
`vertically disposed‘loops 48 and 50 positioned adjacent
`to each other such that one portion or “leg" 49 of the
`loop 48 is directly adjacent one leg 51 of the loop 50.
`The conduit 42 is supported on a mounting plate 54
`having an upstanding wall 56, and a base portion 58
`with a slot 60, FIG. 5, formed therein for supporting the
`conduit 42, as illustrated. A suitable vibrator device 62
`is mounted on the wall 56 and is engaged with the legs
`49 and 51 of the respective tube loops 48 and 50 for
`vibrating the legs 49 and 51 laterally with respect to
`their central longitudinal axes.
`As shown in FIG. 4, suitable pressure transducers 64
`and 66 are mounted on the tube leg 49 opposed to each
`other and aligned with the direction of vibration or
`oscillatory movement of the tubing legs 49 and 51, as
`indicated by the arrows 65. A third pressure transducer
`68 is mounted on the tubing leg 51, as indicated in FIG.
`4, for measuring pressures within the leg. FIG. 5 illus-
`trates also how the loops 48 and 50, including their
`respective legs 49 and 51, oscillate about a pivot point
`formed by the portions of the tube 42 which lie .in the
`slot 60. For example, the loop 48 generally pivots about
`the central longitudinal axis of the leg 43, FIG. 2, and
`the loop 50, in like manner, pivots about the longitudi-
`nal central axis of the leg 47, both of which lie coaxially
`with respect to each other in the slot 60.
`The apparatus 40 may be used in determining the
`volumetric and mass flow rates of a multiphase fluid
`stream in place of the flow meter 16. For example, the
`volumetric flow rate (Qm) of the fluid flow stream
`maybe determined from the equation:
`
`5
`
`IO
`
`15
`
`2O
`
`25
`
`30
`
`35
`
`40
`
`Qm=Ac[{(P66—P¢g)—de}/{ 19.7 xDxdm XH-
`z(A/H)l]
`
`(H)
`
`45
`
`where A: is the cross sectional area of the conduit 42 at
`the measurement point, P56 and P63 are the pressures
`measured at the transducers 66 and 68 at the instant of
`peak lateral acceleration of the legs 49 and 51, respec-
`tively, D is the tube inner diameter, dm is the density of
`the fluid mixture in the tube, which may be determined
`by one of the aforementioned methods, A is the ampli-
`tude of vibration of the loops 48 and 50, Hz is the fre-
`quency of vibration of loops 48 and 50, H is the distance
`indicated in FIG. 5 between the pivot point of vibration
`of the loops 48 and 50 and the point of measurement of
`the pressures P66 and P63 and de is the friction pressure
`drop between the transducers 66 and 68 which is an
`average value of the difference in the pressures P66 and
`P53 over a period of time greater than about ten oscilla-
`tions of the loops 48 and 50.
`Typical order of magnitude values of the difference
`between the peak pressures P66 and P63 are indicated
`below for a tube or conduit having a nominal diameter
`of 2.0 inches and a fluid mixture flowing therethrough
`having a density of 2.0 slugs and a ratio of vibration
`amplitude (A) to (H) of 1:50. It will be seen that for a
`vibratory frequency of 80 Hz and for the fluid velocities
`
`50
`
`55
`
`65
`
`6
`(v) indicated below, that the required sensitivity of the
`transducers 66 and 68 will be as indicated by the last
`column which is the derivative of pressure with respect
`to time.
`
`\'
`ft/sec.
`2
`20
`
`Pbfi-Pfis-dpf
`(psi)
`.073
`.730
`
`d(P66—P¢g)/dl
`(psi/sec.)
`36
`360
`
`Again, in cases where the water density, oil density
`and gas density are known and are relatively stable from
`time to time, the apparatus 40 may also be used to deter-
`mine the gas fraction,
`fg, of the mixture flowing
`through the conduit 10 utilizing the meter 14, the flow
`meter 36 or 16 and the apparatus 40.
`Referring further to FIG. 4, the apparatus 40 may
`also include a transducer or accelerometer 70 mounted
`on the conduit leg 49 in such a way as to measure accel-
`erations of the leg 49 in the directions of the arrows 65.
`The transducers 64, 66, 68 and 70 may be connected to
`a suitable control system including an analog to digital
`interface 72, a controller 74, a computer or “CPU” 76
`and a frequency spectrum analyzer 78. The volumetric
`or mass flow rate of a fluid mixture flowing through the
`apparatus 40 may also be determined by measuring the
`gas fraction mixture (fg) using the apparatus 40 instead
`of other methods. The measurement may be carried out
`by vibrating the conduit leg 49 in the direction of the
`arrows 65 at the natural frequency of vibration (fn) of
`the liquid mixture flowing through the leg 49. Assume
`that the natural frequency of vibration (fn) of the fluid
`mixture flowing through the leg 49 has a generally
`sinusoidal waveform and a phase lag, as measured by
`the transducer 64 or 66, of approximately 90 degrees
`with respect to the waveform of the vibration of the
`conduit leg 49 as measured by the transducer 70. The
`vibrator 62 may be controlled to sweep through a range
`of frequencies while measuring the phase angle of vibra-
`tion of the fluid mixture as determined by the trans-
`ducer 66 as compared with the waveform of the vibra-
`tion of the leg 49 as determined by the transducer 70.
`When this phase angle is 90 degrees, as determined by
`the spectrum analyzer 78, the “sloshing” natural fre-
`quency (fn) of the compressible mixture of fluid in the
`leg 49 may be noted and the following equation solved
`for the gas fraction, fg:
`
`_1__ _ I,
`dm§4Dtn22
`I/P — b
`
`fg
`
`_
`‘
`
`'
`
`(13)
`
`where dm is the density of the fluid mixture, D is the
`inside diameter of the conduit leg 49, b is the bulk com-
`pressibility of the liquid in the fluid mixture, which can
`be assumed, and P is the nominal fluid pressure in the
`conduit leg 49. In the limit, as the gas fraction, fg, ap-
`proaches O or I, the natural frequency of vibration of
`the fluid mixture will become that corresponding to the
`quarter wave resonance of a sonic wave in the conduit
`leg 49, that is, the medium being all liquid (fg=0) and all
`gas (fg: 1), respectively. Predicted values of fn for a 1.0
`inch, 2.0 inch, and 3.0 inch diameter pipe, assuming that
`the density of liquid is 60 lb./ft.3, the bulk compressibil-
`ity of the liquid is 3.5x lO-6 in.2/lb. and the nominal
`pressure is 500 psig, indicate the natural sloshing fre-
`
`6
`
`

`

`5,224,372
`
`7
`quency of the fluid mixture will be in a range of sound
`detectable by the human ear.
`An advantage of the arrangement illustrated in FIG.
`4 and the method described above, is that, in high pres-
`sure applications, conventional coriolis flow meters
`require that the pipe or conduit be so stiff that a signal
`to noise ratio is too small for accurate measurements.
`The apparatus 40 may be operated to determine the
`density (dm) of the fluid mixture if the gas fraction (fg)
`is known and equation (13) is solved for dm.
`The oil, water and gas flow rates Qo, Qw, and Qg are
`each computed by equations (4) through (6) in which
`Qm is the volumetric flow rate determined from the
`flow meters 36 or 16. The meter 16 need not be used in
`
`10
`
`15
`
`8
`fluids flowing through the tubes are measured and re-
`lated to density and volumetric or mass flow rate.
`Although preferred embodiments of the present in-
`vention have been described in detail herein,
`those
`skilled in the art will recognize that various substitu-
`tions and modifications may be made to the specific
`embodiments described without departing from the
`scope and spirit of the invention recited in the appended
`claims.
`What is claimed is:
`1. A method of determining the gas fraction of a
`multiphase fluid flowstream comprising gas, and at least
`two liquids in the liquid phase comprising the steps of:
`providing means for measuring the true density of the
`fluid flowstream and a Coriolis device for deter-
`mining the apparent density of the fluid flow-
`stream;
`flowing the fluid flowstream through said means and
`said device thereby measuring the true and appar-
`ent densities of the fluid; and
`determining the gas fraction based on the true density
`of the fluid flowstream and the apparent density of
`the fluid flowstream.
`2. The method set forth in claim 1 including the step
`Of:
`measuring the mass flow rate of the fluid flowstream
`with the coriolis device; and
`.
`determining the volumetric flow rate of the fluid
`flowstream based on the mass flow rate and the
`
`density of the fluid flowstream.
`3. The method set forth in claim 2 including the steps
`of:
`
`providing means for measuring the liquid fraction of
`at least one of the two liquids in the fluid flow-
`stream;
`-
`measuring the liquid fraction of said at least one liq-
`uid;
`determining at least one of the volumetric flow rate
`of the liquid phases and the gas phase in the fluid
`flowstream based on the volumetric flow rate of
`the fluid flowstream, the gas fraction, and the liq-
`uid fraction of said at least one liquid.
`4. The method set forth in claim 1, wherein: said
`Coriolis device comprises at
`least one tube through
`which the fluid flowstream is conveyed, said tube is
`vibrated in a lateral direction with respect to the direc-
`tion of flow of fluid through said coriolis device and the
`gas fraction (fg) is determined by the relationship:
`
`_ QAI‘} — 4,430 — dm/dma]
`f3—
`2A3
`
`-
`
`wherein dma is the apparent density of the mixture as
`determined by the Coriolis device, dm is the true den-
`sity of the fluid mixture and A2 and A3 are empirical
`coefficients obtained by-calibrating said coriolis device
`with gassy liquid flow.
`5. A method of determining the gas fraction of a
`multiphase fluid flowstream comprising gas, and at least
`two liquids in the liquid phase wherein the density of
`the gas and the liquids is known, comprising the steps
`of:
`
`providing a Coriolis device for measuring the appar-
`ent density of the fluid flowstream and a meter for
`determining the fraction of one liquid in the liquid
`phase of the fluid flowstream;
`
`the method just described but the fluid densities do, dw,
`dg and the bulk compressibility, b, as well as the pres-
`sure, P, must be known.
`Alternatively, the apparatus may be operated to ef-
`fect vibration of the conduit leg 49 at a frequency far
`from the “sloshing” natural frequency of the fluid mix- 20
`ture flowing through the conduit 42. Under these cir-
`cumstances lateral acceleration in the direction of the
`arrows 65 will match those of the vibrating conduit leg
`49. Accordingly, by sweeping the frequency of vibra-
`tion induced by the vibrator 62 through a range and
`noting the accelerations measure by the transducers 64,
`66 and 70, while also simultaneously measuring the
`pressure at the points of measurement determined by
`the transducers 64 and 66, will yield an oscillating pres-
`sure whose amplitude is related to fluid density by the
`equation:
`
`25
`
`30
`
`dm =(g) (P1 —PZ)/(D'A(277Hz)2)
`
`(14)
`
`35
`
`where g is the gravitational constant, P1 and P2 are the
`pressures measured at the respective opposed transduc-
`ers 64 and 66, D is the inside diameter of the conduit leg
`49, A is the amplitude of vibration of the conduit leg 49
`and Hz is the frequency of vibration of the conduit leg.
`The oil, water and gas flow rates can thus be com—
`puted by equations (4) through (6). The flow meter 36
`or 16 may be used to determine Qm.
`Conventional coriolis meters determine the fluid mix-
`
`50
`
`55
`
`ture density (dm) by measuring the natural frequency of 45
`the “pipe-fluid" combination. This arrangement has
`worked well when structural stiffness of the pipe is not
`high, such as would be required in relatively high pres-
`sure applications as mentioned above. However,
`the
`pipe stiffness does not affect the determination of the
`fluid mixture density (dm) in the methods described
`above. Other advantages of these methods are that the
`noise to signal problems such as those which are inher-
`ent in conventional coriolis meters are absent, entrained
`gas bubbles should not adversely affect
`the density
`measurement, as long as the vibration frequency is far
`from the natural sloshing frequency and only one tube
`or conduit need be used to obtain the fluid mixture
`density data, thereby minimizing pressure drops across
`the flowmeter. Moreover, precise dimensions and dy-
`namic balancing of the conduit is not required, such as
`is the case with conventional coriolis type flow meters.
`Volumetric and mass flow rates may thus be deter-
`mined for a mixed phase fluid from a relatively simple
`single tube flow meter wherein the coriolis effects are
`measured more directly than with conventional coriolis
`flow meters. Instead of measuring the distortion and
`resonance of vibrating tubes, the actual pressures of the
`
`65
`
`7
`
`

`

`5,224,372
`
`10
`of the fluid mixture, and, A2 and A3 are empirical coef-
`ficients obtained by calibrating said densimeter with
`gassy liquid flow.
`10. A method for determining the gas fraction of a
`fluid mixture comprising gas and at least two liquids in
`a liquid phase, comprising the steps of:
`providing a flow meter characterized by a tube which
`is operable to be vibrated laterally with respect to
`the direction of flow of said fluid mixture through
`said tube, means for sensing the peak fluid pressure
`in said tube and the nominal fluid pressure in said
`tube, and means for measuring the frequency of
`vibration of said tube;
`determining the density of the fluid mixture flowing
`through said tube;
`.
`vibrating said tube at a range of frequencies;
`measuring the peak pressure in sad tube in relation to
`the vibration of said tube to determine when sad
`
`tube is vibrating at the sloshing natural frequency
`of vibration of said fluid mixture; and
`determining the gas fraction of the fluid mixture flow-
`ing through said tube based on the nominal pres-
`sure sensed by said pressure sensing means, said
`natural frequency of vibration of said fluid mixture,
`the density of said fluid mixture flowing through
`said tube, the bulk compressibility of the liquid in
`said fluid mixture and the diameter of said tube.
`11. The method set forth in claim 10 wherein:
`determining the sloshing natural frequency of vibra-
`tion of said fluid mixture comprises comparing the
`phase angle of the waveform of said peak pressure
`with the phase angle of the waveform of said vibra-
`tion of said tube.
`12. The method set forth in claim 10 wherein:
`
`the step of determining the density of said fluid mix-
`ture includes:
`
`providing pressure sensing means disposed opposed
`to each other along a line which is parallel to the
`direction of vibration of said tube;
`vibrating said tube at a frequency far from the slosh-
`ing natural frequency of vibration of the fluid mix-
`ture while measuring the pressure at the opposed
`pressure sensing means; and
`determining the density of the fluid mixture based on
`the pressure difference measured at the opposed
`pressure sensing means, the diameter of the tube,
`the amplitude of vibration of the tube and the fre-
`quency of vibration of the tube.
`t
`t
`t
`t
`t
`
`9
`flowing the fluid flowstream through said meter and
`said device thereby measuring the apparent density
`and fraction of one liquid; and
`determining the gas fraction based on the measured
`apparent density of the fluid flowstream,
`the
`known densities of the gas and the liquids and the
`measured fraction of one liquid in the liquid phase.
`6. The method set forth in claim 5 including the steps
`of:
`.
`measuring the mass flow rate of the fluid flOWStream
`with the Coriolis device; and
`determining the volumetric flow rate of the fluid
`flowstream based on the measured mass flow rate
`and the density of the fluid flowstream.
`7. The method set forth in claim 6 including the steps
`of:
`
`determining the volumetric flow rate of at least one
`of the liquid phases and the gas phase in the fluid
`flowstream based on the volumetric flow rate of
`the fluid flowstream, the gas fraction, and the liq-
`uid fraction of said at least one liquid.
`8. The method set forth in claim 5 wherein:
`the fluid flowstream comprises a mixture of oil, water
`and a gas and the gas fraction is determined from
`the relationship:
`
`_ db: — 406
`fs — _20
`
`where fg is the gas fraction, we is the fraction of water
`in the liquid phase, do is the density of oil in the liquid
`phase, dw is the density of water in the liquid phase, dg
`is the gas density, dma is the apparent density of the
`fluid mixture,
`a=dma*A3
`b=dma‘A2+wc(dw-do)+(do—dg)
`c=dma—wc(dw—do)—do
`and A2 and A3 are empirical coefficients.
`9. The method set forth in claim 5, wherein:
`the Coriolis device comprises at
`least one tube
`through which the fluid flowstream is conveyed,
`said tube is vibrated in a lateral direction with re-
`
`10
`
`15
`
`20
`
`25
`
`30
`
`35
`
`40
`
`spect to the direction of flow of fluid through said
`coriolis device and the density of the mixture (dm)
`is determined by the relationship:
`
`45
`
`dm=dma(l ”MN/13%!)
`
`wherein dma is the apparent density of the mixture as
`determined by the coriolis device, fg is, the gas fraction
`
`50
`
`55
`
`65
`
`8
`
`