CA1329271C - Means and method for monitoring the flow of a multi-phase petroleum stream - Google Patents
Means and method for monitoring the flow of a multi-phase petroleum streamInfo
- Publication number
- CA1329271C CA1329271C CA000563866A CA563866A CA1329271C CA 1329271 C CA1329271 C CA 1329271C CA 000563866 A CA000563866 A CA 000563866A CA 563866 A CA563866 A CA 563866A CA 1329271 C CA1329271 C CA 1329271C
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- 239000003208 petroleum Substances 0.000 title claims abstract description 67
- 238000000034 method Methods 0.000 title claims abstract description 10
- 238000012544 monitoring process Methods 0.000 title claims abstract description 8
- 239000007788 liquid Substances 0.000 claims abstract description 50
- 239000012530 fluid Substances 0.000 claims description 4
- 230000000875 corresponding effect Effects 0.000 claims 14
- 239000003795 chemical substances by application Substances 0.000 description 4
- 238000010586 diagram Methods 0.000 description 3
- 238000009795 derivation Methods 0.000 description 2
- 230000005251 gamma ray Effects 0.000 description 2
- 241000237858 Gastropoda Species 0.000 description 1
- 230000001133 acceleration Effects 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
Classifications
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
- G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
- G01F1/76—Devices for measuring mass flow of a fluid or a fluent solid material
- G01F1/86—Indirect mass flowmeters, e.g. measuring volume flow and density, temperature or pressure
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
- G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
- G01F1/704—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow using marked regions or existing inhomogeneities within the fluid stream, e.g. statistically occurring variations in a fluid parameter
- G01F1/708—Measuring the time taken to traverse a fixed distance
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
- G01N33/26—Oils; Viscous liquids; Paints; Inks
- G01N33/28—Oils, i.e. hydrocarbon liquids
- G01N33/2823—Raw oil, drilling fluid or polyphasic mixtures
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- Health & Medical Sciences (AREA)
- Fluid Mechanics (AREA)
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Food Science & Technology (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- General Chemical & Material Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Medicinal Chemistry (AREA)
- Analytical Chemistry (AREA)
- Biochemistry (AREA)
- General Health & Medical Sciences (AREA)
- Immunology (AREA)
- Pathology (AREA)
- Measuring Volume Flow (AREA)
- Investigating, Analyzing Materials By Fluorescence Or Luminescence (AREA)
Abstract
MEANS AND METHOD FOR MONITORING THE FLOW
OF A MULTI-PHASE PETROLEUM STREAM
(D#77,945-F) ABSTRACT
The multi-phase petroleum stream monitor includes two densitometers which measure the density of the petroleum stream at two locations and provides corresponding signals. The temperature and the pressure of the petroleum stream are also measured and corresponding signals provided. Apparatus provides signals corresponding to the density of the liquid in the petroleum stream and to the density of the gas in the petroleum stream. The liquid flow rate and the gas flow rate of the petroleum stream are determined in accordance with the two sensed density signals, the temperature signal, the pressure signal, the liquid density signal and the gas density signal.
OF A MULTI-PHASE PETROLEUM STREAM
(D#77,945-F) ABSTRACT
The multi-phase petroleum stream monitor includes two densitometers which measure the density of the petroleum stream at two locations and provides corresponding signals. The temperature and the pressure of the petroleum stream are also measured and corresponding signals provided. Apparatus provides signals corresponding to the density of the liquid in the petroleum stream and to the density of the gas in the petroleum stream. The liquid flow rate and the gas flow rate of the petroleum stream are determined in accordance with the two sensed density signals, the temperature signal, the pressure signal, the liquid density signal and the gas density signal.
Description
~ 3~9 ~7 1 6n288-2804 BACKGROUND OF THE INVENTION
Field of the Invention The present invention relates to monitoring of a petroleum stream in general and, more particularly, to moni-toring the flow of a multi-phase petroleum stream.
SUMMARY OF THE INVENTION
The multi-phase petroleum stream monitor includes two densitometers which measure the density of the petroleum stream at two locations and provides corresponding signals. The temperature and the pressure of the petroleum stream are also measured and corresponding signals provided. Apparatus provides signals corresponding to the density of the liquid in the petroleum stream and to the density of the gas in the petroleum stream. The liquid flow rate and the gas flow rate of the petroleum stream are determined in accordance with the two sensed density signals, the temperature signal, the pressure signal, the liquid density signal and the gas density signal.
In summary, the present invention provides, according to a first aspect, apparatus for monitoring a multi-phase petroleum stream flowing in a pipe comprising: two density sensing means for sensing the density of the petroleum stream at two locations a known distance apart and providing sensed density signals, corresponding to the sensed densities which are related to a fluid velocity of the petroleum stream, temperature sensing means for sensing the temperature of the petroleum stream and providing a temperature signal representa-tive of the sensed temperature, pressure sensing means for . k~, .~ .
1 32927i1 60288-2804 sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, and flow rate means connected to both density sensing means, to :i the pressure sensing means and to the temperature sensing means for entering known values of gas density, liquid density and a surface tension of gas and for providing signals corresponding g to the liquid flow rate and to the gas flow rate of the I petroleum stream in accordance with the sensed density signals, ~ i the temperature signal, the pressure signal and entered known values of the gas and the liquid.
According to a second aspect, the present invention provides a method of monitoring a multi-phase petroleum stream flowing in a pipe comprising the steps of: sensing the density of the petroleum stream at two locations a known distance apart, providing sensed density signals corresponding :
i to the sensed densities and which are related to the fluid velocity of the petroleum stream, sensing the temperature of the petroleum stream and providing a temperature signal representative of the sensed temperature, sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, determining a density of the liquid in the petroleum stream, determining a surface tension of gas in the petroleum stream, determining a density of the gas in the petroleum stream, and providing signals corresponding to the liquid flow rate and to the gas flow rate of the petroleum stream in accordance with the sensed density -la-, :
"
, .......................... .
1 3~9~7 ~
signals, the temperature signal, the determined liquid density, the determined gas surface tension and the determined gas density.
The objects and advantages of the invention will appear more fully hereinafter from a consideration of the detailed description which follows, taken together with the accompanying drawings wherein one embodiment of the invention is illustrated by way of example. It is to be expressly understood, however, that the drawings are for illustration purposes only and are not to be construed as defining the limits of the invention.
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DESCRIPTION OF THE DRAWINGS
Figure 1 is a simplified block diagram of a multi-phase petroleum stream monitor constructed in accordance with the present invention.
.
Figure 2 represents waveforms of signals El and E2 provided by the detectors shown in Figure 1.
, . .
Figure 3 is a flow diagram of steps utilizing the computer means shown in Figure 1 to arrive at the flow rates for the gas and the liquid in the petroleum stream.
DESCRIPTION OF THE INVENTION
The present invention monitors the gas flow rate and - the liquid flow rate of a multi-phase petroleum stream utilizing well known equations. The following Table I relates terms of the equations and thei~ definitions:
: TABLE I
UT = velocity of large gas bubbles UGS = gas superficial veloci~y UL5 = liquid superficial velocity A = cross-sectional area of pipe AG = cross-sectional area of gas bubble G = length of gas bubble = length from end of one bubble to end of next bubble = fraction of gas in liquid slug section LS
Field of the Invention The present invention relates to monitoring of a petroleum stream in general and, more particularly, to moni-toring the flow of a multi-phase petroleum stream.
SUMMARY OF THE INVENTION
The multi-phase petroleum stream monitor includes two densitometers which measure the density of the petroleum stream at two locations and provides corresponding signals. The temperature and the pressure of the petroleum stream are also measured and corresponding signals provided. Apparatus provides signals corresponding to the density of the liquid in the petroleum stream and to the density of the gas in the petroleum stream. The liquid flow rate and the gas flow rate of the petroleum stream are determined in accordance with the two sensed density signals, the temperature signal, the pressure signal, the liquid density signal and the gas density signal.
In summary, the present invention provides, according to a first aspect, apparatus for monitoring a multi-phase petroleum stream flowing in a pipe comprising: two density sensing means for sensing the density of the petroleum stream at two locations a known distance apart and providing sensed density signals, corresponding to the sensed densities which are related to a fluid velocity of the petroleum stream, temperature sensing means for sensing the temperature of the petroleum stream and providing a temperature signal representa-tive of the sensed temperature, pressure sensing means for . k~, .~ .
1 32927i1 60288-2804 sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, and flow rate means connected to both density sensing means, to :i the pressure sensing means and to the temperature sensing means for entering known values of gas density, liquid density and a surface tension of gas and for providing signals corresponding g to the liquid flow rate and to the gas flow rate of the I petroleum stream in accordance with the sensed density signals, ~ i the temperature signal, the pressure signal and entered known values of the gas and the liquid.
According to a second aspect, the present invention provides a method of monitoring a multi-phase petroleum stream flowing in a pipe comprising the steps of: sensing the density of the petroleum stream at two locations a known distance apart, providing sensed density signals corresponding :
i to the sensed densities and which are related to the fluid velocity of the petroleum stream, sensing the temperature of the petroleum stream and providing a temperature signal representative of the sensed temperature, sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, determining a density of the liquid in the petroleum stream, determining a surface tension of gas in the petroleum stream, determining a density of the gas in the petroleum stream, and providing signals corresponding to the liquid flow rate and to the gas flow rate of the petroleum stream in accordance with the sensed density -la-, :
"
, .......................... .
1 3~9~7 ~
signals, the temperature signal, the determined liquid density, the determined gas surface tension and the determined gas density.
The objects and advantages of the invention will appear more fully hereinafter from a consideration of the detailed description which follows, taken together with the accompanying drawings wherein one embodiment of the invention is illustrated by way of example. It is to be expressly understood, however, that the drawings are for illustration purposes only and are not to be construed as defining the limits of the invention.
-lb-- ~ :
'' ' '' ' `
~ 3~9~1 ~
DESCRIPTION OF THE DRAWINGS
Figure 1 is a simplified block diagram of a multi-phase petroleum stream monitor constructed in accordance with the present invention.
.
Figure 2 represents waveforms of signals El and E2 provided by the detectors shown in Figure 1.
, . .
Figure 3 is a flow diagram of steps utilizing the computer means shown in Figure 1 to arrive at the flow rates for the gas and the liquid in the petroleum stream.
DESCRIPTION OF THE INVENTION
The present invention monitors the gas flow rate and - the liquid flow rate of a multi-phase petroleum stream utilizing well known equations. The following Table I relates terms of the equations and thei~ definitions:
: TABLE I
UT = velocity of large gas bubbles UGS = gas superficial veloci~y UL5 = liquid superficial velocity A = cross-sectional area of pipe AG = cross-sectional area of gas bubble G = length of gas bubble = length from end of one bubble to end of next bubble = fraction of gas in liquid slug section LS
~ TB = fraction of gas ~n ga~s ~ubble section QG = gaS f low rate QL = liquid flow rate ~G = density of gas ~L = density of liquid ~-g = surface tension of gas D = diameter of pipe g = acceleration of gravity p = pressure T = temperature.
.
The equations disclosed in A. E. Dukler's course on gas-liquid flow given at the University of Houston, Houston, Texas, lead to equation 1:
1. UGs A = [AG ~ G + A ( ~ ~) LS T
Equation 1 may be rewritten as equation 2 following:
GS [~G TB (~ ~G) LS]/( ~ /UT) Equation 3 written as follows:
.
The equations disclosed in A. E. Dukler's course on gas-liquid flow given at the University of Houston, Houston, Texas, lead to equation 1:
1. UGs A = [AG ~ G + A ( ~ ~) LS T
Equation 1 may be rewritten as equation 2 following:
GS [~G TB (~ ~G) LS]/( ~ /UT) Equation 3 written as follows:
3. UT 1.2 (ULs GS) [5~g (~L ~G)/ / L ] +,35 l~ gD
': ` " ' ~
,.~
S ~ T g ( L ~G) / / L ] - . 35 ~gD -1 2U 3 /1 2 From the superficial velocities UGS and ULS of the gas and the liquid, respectively, the flow rate of the gas QG
and the flow rate QL of the liquid can be determined from equations 5 and 6, following:
S QG = (UGS) AG
6- QL ~ (ULS) (A AG) Thus in vertical flow which is shown in Figure l, 15 there is shown a petroleum stream 3 flowing in a pipe 7.
Within petroLeum stream 3 there are gas bubbles ll and further within the liquid slugs there is dispersed gas 14. A liquid slug is that portion of the petroleum stream between two bubbles.
In this particular example, there is shown sources 20 and 23 of gamma energy which provide beams across petroleum stream 3 where they are detected by detectors 28 and 30, respectively. Although the present example shows a slug detector as being composed of a gamma ray source with a gamma ray detector, other types of slug detectors may be used to determine the density of the liquid flowing past a particular point. For example X-ray sources and sensors, ultrasonic sources and sensors are some. Further, sources 20 and 23 are located a predetermined distance d apart. Detectors 28, 30 provide density signals El and E2, respectively, to computer means 36. Computer means 36 may be a general purpose digital computer.
A pressure sensor 40 and a temperature sensor 42 senses the pressure and temperature of petroleum stream 3, r~
~.`
~, respectively, and provides a pressure signal p and a temperature signal T, respectively, to computer means 36.
Also shown in Eigure l, for purposes of explanation, length -~ G is graphically defined as the length of a bubble and length ~ as being the distance from the start of one bubble to the start of the next subsequent bubble.
Figure 2 ~hows two plots of signals El and E2 of density versus time. For the purpose of explaining various times used in the specification, ~ t is shown as the time differential between the leading edge of a bubble passing detector 30 and its subsequent passage of detector 28. It is obvious that ~ t with the known distance d can be used to derive the velocity UT of the gas bubble. Further, tl defines the time for length of passage of a gas bubble, while t2 defines the time from the start of one gas bubble to the start of the next subsequent gas bubble.
.
With reference to the flow diagram of Figure 3, values for the Lab determined density of the gas, density of the liquid and the surface tension of the gas are entered into computer means 36. Computer means 36 then senses the densities of the petroleum signals in accordance with signals El and E2.
The pressure of the petroleum stream in accordance with signal p and the temperature of the petroleum stream in accordance with signal t. The pressure signal p and temperature signal t are used to correct the densities ~ L and ~G already entered into computer means 36 as is shown in block 89. The next step is to derive UT (per block 93) from the simple expediency of dividing the distance d by ~ t.
In block 97 computer means 36 is programmed to derive ~ LS and ~'< TB. As noted, ~ LS is the fraction of gas in the liquid slug and ~C TB is the fraction of gas in the gas bubble. Density signals El and E2 are used in this derivation and results from calibration data taken wherein the 1 32q ~7 l densities of the various composition of liquid and gas in the pipe are determined as stored in computer means 36 memory.
Block 100 provides for the derivation of the terms ~ and ~G which is accomplished by computer means 36. By knowing the value for UT, computer means 36 can then use its internal clock to determine ~G and ~ . Block 110 pertains to the deriving of the gas superficial velocity UGS utilizing equation 2. Block 114 provides for computer means 36 to derive the liquid superficial velocity ULS.
The final step in block 120 is to derive the gas flow rate QG and the liquid flow rate QL in accordance with : equations 5 and 6, respectively. Although Figure 1 doesn't show it, computer means 36 may be providing an output to recording means to record the data.
. The present invention may also be used for horizontal flow wherein equation 3 is rewritten as ; 7. UT = C(ULS + UGS) i where C is a constant having a value in a range of 1.2 to 1.3, and UO is a substantially constant velocity determined by lab , flow calibration.
"
"
... .
. --6--
': ` " ' ~
,.~
S ~ T g ( L ~G) / / L ] - . 35 ~gD -1 2U 3 /1 2 From the superficial velocities UGS and ULS of the gas and the liquid, respectively, the flow rate of the gas QG
and the flow rate QL of the liquid can be determined from equations 5 and 6, following:
S QG = (UGS) AG
6- QL ~ (ULS) (A AG) Thus in vertical flow which is shown in Figure l, 15 there is shown a petroleum stream 3 flowing in a pipe 7.
Within petroLeum stream 3 there are gas bubbles ll and further within the liquid slugs there is dispersed gas 14. A liquid slug is that portion of the petroleum stream between two bubbles.
In this particular example, there is shown sources 20 and 23 of gamma energy which provide beams across petroleum stream 3 where they are detected by detectors 28 and 30, respectively. Although the present example shows a slug detector as being composed of a gamma ray source with a gamma ray detector, other types of slug detectors may be used to determine the density of the liquid flowing past a particular point. For example X-ray sources and sensors, ultrasonic sources and sensors are some. Further, sources 20 and 23 are located a predetermined distance d apart. Detectors 28, 30 provide density signals El and E2, respectively, to computer means 36. Computer means 36 may be a general purpose digital computer.
A pressure sensor 40 and a temperature sensor 42 senses the pressure and temperature of petroleum stream 3, r~
~.`
~, respectively, and provides a pressure signal p and a temperature signal T, respectively, to computer means 36.
Also shown in Eigure l, for purposes of explanation, length -~ G is graphically defined as the length of a bubble and length ~ as being the distance from the start of one bubble to the start of the next subsequent bubble.
Figure 2 ~hows two plots of signals El and E2 of density versus time. For the purpose of explaining various times used in the specification, ~ t is shown as the time differential between the leading edge of a bubble passing detector 30 and its subsequent passage of detector 28. It is obvious that ~ t with the known distance d can be used to derive the velocity UT of the gas bubble. Further, tl defines the time for length of passage of a gas bubble, while t2 defines the time from the start of one gas bubble to the start of the next subsequent gas bubble.
.
With reference to the flow diagram of Figure 3, values for the Lab determined density of the gas, density of the liquid and the surface tension of the gas are entered into computer means 36. Computer means 36 then senses the densities of the petroleum signals in accordance with signals El and E2.
The pressure of the petroleum stream in accordance with signal p and the temperature of the petroleum stream in accordance with signal t. The pressure signal p and temperature signal t are used to correct the densities ~ L and ~G already entered into computer means 36 as is shown in block 89. The next step is to derive UT (per block 93) from the simple expediency of dividing the distance d by ~ t.
In block 97 computer means 36 is programmed to derive ~ LS and ~'< TB. As noted, ~ LS is the fraction of gas in the liquid slug and ~C TB is the fraction of gas in the gas bubble. Density signals El and E2 are used in this derivation and results from calibration data taken wherein the 1 32q ~7 l densities of the various composition of liquid and gas in the pipe are determined as stored in computer means 36 memory.
Block 100 provides for the derivation of the terms ~ and ~G which is accomplished by computer means 36. By knowing the value for UT, computer means 36 can then use its internal clock to determine ~G and ~ . Block 110 pertains to the deriving of the gas superficial velocity UGS utilizing equation 2. Block 114 provides for computer means 36 to derive the liquid superficial velocity ULS.
The final step in block 120 is to derive the gas flow rate QG and the liquid flow rate QL in accordance with : equations 5 and 6, respectively. Although Figure 1 doesn't show it, computer means 36 may be providing an output to recording means to record the data.
. The present invention may also be used for horizontal flow wherein equation 3 is rewritten as ; 7. UT = C(ULS + UGS) i where C is a constant having a value in a range of 1.2 to 1.3, and UO is a substantially constant velocity determined by lab , flow calibration.
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"
... .
. --6--
Claims (14)
1. Apparatus for monitoring a multi-phase petroleum stream flowing in a pipe comprising:
two density sensing means for sensing the density of the petroleum stream at two locations a known distance apart and providing sensed density signals, corresponding to the sensed densities which are related to a fluid velocity of the petroleum stream, temperature sensing means for sensing the temperature of the petroleum stream and providing a temperature signal representative of the sensed temperature, pressure sensing means for sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, and flow rate means connected to both density sensing means, to the pressure sensing means and to the temperature sensing means for entering known values of gas density, liquid density and a surface tension of gas and for providing signals corres-ponding to the liquid flow rate and to the gas flow rate of the petroleum stream in accordance with the sensed density signals, the temperature signal, the pressure signal and entered known values of the gas and the liquid.
two density sensing means for sensing the density of the petroleum stream at two locations a known distance apart and providing sensed density signals, corresponding to the sensed densities which are related to a fluid velocity of the petroleum stream, temperature sensing means for sensing the temperature of the petroleum stream and providing a temperature signal representative of the sensed temperature, pressure sensing means for sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, and flow rate means connected to both density sensing means, to the pressure sensing means and to the temperature sensing means for entering known values of gas density, liquid density and a surface tension of gas and for providing signals corres-ponding to the liquid flow rate and to the gas flow rate of the petroleum stream in accordance with the sensed density signals, the temperature signal, the pressure signal and entered known values of the gas and the liquid.
2. Apparatus as described in claim 1 in which the flow rate means includes:
correction means connected to the temperature sensing means and the pressure sensing means for providing a corrected liquid density signal and a corrected gas density signal corresponding to the liquid density and the gas density, respectively, corrected for the temperature and the pressure of the petroleum stream in accordance with the entered values, density, the temperature signal and the pressure signal.
correction means connected to the temperature sensing means and the pressure sensing means for providing a corrected liquid density signal and a corrected gas density signal corresponding to the liquid density and the gas density, respectively, corrected for the temperature and the pressure of the petroleum stream in accordance with the entered values, density, the temperature signal and the pressure signal.
3. Apparatus as described in claim 2 in which the flow rate means includes:
gas superficial velocity means connected to the correction means and to both density sensing means for providing a signal corresponding to the superficial velocity of the gas in the petroleum stream in accordance with the sensed density signals from both density sensing means.
gas superficial velocity means connected to the correction means and to both density sensing means for providing a signal corresponding to the superficial velocity of the gas in the petroleum stream in accordance with the sensed density signals from both density sensing means.
4. Apparatus as described in claim 3 in which the gas superficial velocity means includes:
means connected to both density sensing means for deriving the velocity of the petroleum stream in accordance with the sensed density signals from the density sensing means, means connected to both density sensing means for deriving the fraction of gas in a liquid slug and the fraction of gas in a gas bubble in accordance with the sensed density signals, and means connected to at least one of the density sensing means for deriving the distance from the end of one gas bubble to the end of the next gas bubble and the length of a gas bubble in accordance with a sensed density signal from the density sensing means.
means connected to both density sensing means for deriving the velocity of the petroleum stream in accordance with the sensed density signals from the density sensing means, means connected to both density sensing means for deriving the fraction of gas in a liquid slug and the fraction of gas in a gas bubble in accordance with the sensed density signals, and means connected to at least one of the density sensing means for deriving the distance from the end of one gas bubble to the end of the next gas bubble and the length of a gas bubble in accordance with a sensed density signal from the density sensing means.
5. Apparatus as described in claim 4 in which the superficial gas velocity means includes:
network means connected to the stream velocity means, to the gas fraction means and to the length means for providing the superficial gas velocity signal in accordance with the stream velocity signal, the gas fraction in a slug signal, the gas fraction of a bubble signal, the length from the point of one bubble to the corresponding point of another bubble, and the length of a bubble signal.
network means connected to the stream velocity means, to the gas fraction means and to the length means for providing the superficial gas velocity signal in accordance with the stream velocity signal, the gas fraction in a slug signal, the gas fraction of a bubble signal, the length from the point of one bubble to the corresponding point of another bubble, and the length of a bubble signal.
6. Apparatus as described in claim 5 in which the flow rate means includes:
superficial liquid velocity means connected to the gas superficial velocity means, to the correction means and to the network means for providing a signal corresponding to the superficial liquid velocity in accordance with the stream velocity signal, the corrected liquid density signal, the corrected gas density signal and the superficial gas velocity signal.
superficial liquid velocity means connected to the gas superficial velocity means, to the correction means and to the network means for providing a signal corresponding to the superficial liquid velocity in accordance with the stream velocity signal, the corrected liquid density signal, the corrected gas density signal and the superficial gas velocity signal.
7. Apparatus as described in claim 6 in which the flow rate means includes:
circuit means connected to the network means and to the superficial liquid velocity means for providing signals corres-ponding to the flow rate of the gas in the petroleum stream and to the flow rate of the liquid in the petroleum stream in accordance with the superficial liquid velocity signal and the superficial gas velocity signal.
circuit means connected to the network means and to the superficial liquid velocity means for providing signals corres-ponding to the flow rate of the gas in the petroleum stream and to the flow rate of the liquid in the petroleum stream in accordance with the superficial liquid velocity signal and the superficial gas velocity signal.
8. A method of monitoring a multi-phase petroleum stream flowing in a pipe comprising the steps of:
sensing the density of the petroleum stream at two loca-tions a known distance apart, providing sensed density signals corresponding to the sensed densities and which are related to the fluid velocity of the petroleum stream, sensing the temperature of the petroleum stream and provid-ing a temperature signal representative of the sensed temperature, sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, determining a density of the liquid in the petroleum stream, determining a surface tension of gas in the petroleum stream, determining a density of the gas in the petroleum stream, and providing signals corresponding to the liquid flow rate and to the gas flow rate of the petroleum stream in accor-dance with the sensed density signals, the temperature signal, the determined liquid density, the determined gas surface tension and the determined gas density.
sensing the density of the petroleum stream at two loca-tions a known distance apart, providing sensed density signals corresponding to the sensed densities and which are related to the fluid velocity of the petroleum stream, sensing the temperature of the petroleum stream and provid-ing a temperature signal representative of the sensed temperature, sensing the pressure of the petroleum stream and providing a pressure signal in accordance with the sensed pressure, determining a density of the liquid in the petroleum stream, determining a surface tension of gas in the petroleum stream, determining a density of the gas in the petroleum stream, and providing signals corresponding to the liquid flow rate and to the gas flow rate of the petroleum stream in accor-dance with the sensed density signals, the temperature signal, the determined liquid density, the determined gas surface tension and the determined gas density.
9. A method as described in claim 8 in which the flow rate step includes:
providing signals corresponding to the liquid density and the gas density corrected for the temperature and the pressure of the petroleum stream in accordance with the sensed density signals, the temperature signal and the pressure signal.
providing signals corresponding to the liquid density and the gas density corrected for the temperature and the pressure of the petroleum stream in accordance with the sensed density signals, the temperature signal and the pressure signal.
10. A method as described in claim 9 in which the flow rate step includes:
providing a gas superficial velocity signal corresponding to the superficial velocity of the gas in the petroleum stream in accordance with the sensed density signals.
providing a gas superficial velocity signal corresponding to the superficial velocity of the gas in the petroleum stream in accordance with the sensed density signals.
11. A method as described in claim 10 in which the gas superficial velocity step includes:
deriving the velocity of the petroleum stream in accordance with the sensed density signals, deriving the fraction of gas in the liquid slug and the fraction of gas in a gas bubble in accordance with the sensed density signals, and deriving the distance from the end of one gas bubble to the end of the next gas bubble and the length of a gas bubble in accordance with at least one of the sensed density signals.
deriving the velocity of the petroleum stream in accordance with the sensed density signals, deriving the fraction of gas in the liquid slug and the fraction of gas in a gas bubble in accordance with the sensed density signals, and deriving the distance from the end of one gas bubble to the end of the next gas bubble and the length of a gas bubble in accordance with at least one of the sensed density signals.
12. A method as described in claim 11 in which the superficial gas velocity step includes:
providing the superficial gas velocity signal in accordance with the stream velocity signal, the gas fraction in a slug signal, the gas fraction of a bubble signal, the length from the point of one bubble to the corresponding point of another bubble signal, and the length of a bubble signal.
providing the superficial gas velocity signal in accordance with the stream velocity signal, the gas fraction in a slug signal, the gas fraction of a bubble signal, the length from the point of one bubble to the corresponding point of another bubble signal, and the length of a bubble signal.
13. A method as described in claim 12 in which the flow rate step includes:
providing a signal corresponding to the superficial liquid velocity in accordance with the stream velocity signal, the corrected density liquid signal, the corrected gas density signal and the superficial gas velocity signal.
providing a signal corresponding to the superficial liquid velocity in accordance with the stream velocity signal, the corrected density liquid signal, the corrected gas density signal and the superficial gas velocity signal.
14. A method as described in claim 13 in which the flow rate step includes:
providing signals corresponding to the flow rate of the gas in the petroleum stream and to the flow rate of the liquid in the petroleum stream in accordance with the superficial liquid velocity signal and the superficial gas velocity signal.
providing signals corresponding to the flow rate of the gas in the petroleum stream and to the flow rate of the liquid in the petroleum stream in accordance with the superficial liquid velocity signal and the superficial gas velocity signal.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US10294387A | 1987-09-30 | 1987-09-30 | |
| US102,943 | 1987-09-30 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1329271C true CA1329271C (en) | 1994-05-03 |
Family
ID=22292530
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000563866A Expired - Fee Related CA1329271C (en) | 1987-09-30 | 1988-04-12 | Means and method for monitoring the flow of a multi-phase petroleum stream |
Country Status (5)
| Country | Link |
|---|---|
| BR (1) | BR8804831A (en) |
| CA (1) | CA1329271C (en) |
| DK (1) | DK543288A (en) |
| GB (1) | GB2210461B (en) |
| NO (1) | NO175332C (en) |
Families Citing this family (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5103181A (en) * | 1988-10-05 | 1992-04-07 | Den Norske Oljeselskap A. S. | Composition monitor and monitoring process using impedance measurements |
| DE9204374U1 (en) * | 1992-03-31 | 1993-08-12 | Technische Universitaet Muenchen, 80333 Muenchen, De | |
| US5415024A (en) * | 1992-12-16 | 1995-05-16 | Marathon Oil Company | Composition analyzer for determining composition of multiphase multicomponent fluid mixture |
| GB9624899D0 (en) | 1996-11-29 | 1997-01-15 | Schlumberger Ltd | Method and apparatus for measuring flow in a horizontal borehole |
| GB2345141A (en) * | 1998-12-24 | 2000-06-28 | Eastman Kodak Co | Determining the percentage weight of phases in a multi-phase solution |
| NO324812B1 (en) * | 2006-05-05 | 2007-12-10 | Multi Phase Meters As | Method and apparatus for tomographic multiphase flow measurements |
| IT1400011B1 (en) * | 2010-04-29 | 2013-05-09 | Pietro Fiorentini Spa | METHOD OF DETERMINING THE DENSITY OF A MULTIPHASE FLUID, A DENSY METER USING THIS METHOD AND A MULTIFASE METER USING THIS DENSIMETER. |
Family Cites Families (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4815536A (en) * | 1985-03-19 | 1989-03-28 | Noel Carroll | Analysis of multi-phase mixtures |
-
1988
- 1988-04-12 CA CA000563866A patent/CA1329271C/en not_active Expired - Fee Related
- 1988-08-16 GB GB8819488A patent/GB2210461B/en not_active Expired - Fee Related
- 1988-08-25 NO NO883802A patent/NO175332C/en unknown
- 1988-09-19 BR BR8804831A patent/BR8804831A/en not_active IP Right Cessation
- 1988-09-29 DK DK543288A patent/DK543288A/en not_active Application Discontinuation
Also Published As
| Publication number | Publication date |
|---|---|
| GB8819488D0 (en) | 1988-09-21 |
| BR8804831A (en) | 1989-04-25 |
| DK543288D0 (en) | 1988-09-29 |
| NO175332C (en) | 1994-09-28 |
| NO883802L (en) | 1989-03-31 |
| NO883802D0 (en) | 1988-08-25 |
| GB2210461A (en) | 1989-06-07 |
| GB2210461B (en) | 1991-11-27 |
| NO175332B (en) | 1994-06-20 |
| DK543288A (en) | 1989-03-31 |
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| Date | Code | Title | Description |
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| MKLA | Lapsed |