Note: Descriptions are shown in the official language in which they were submitted.
~ 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
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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,
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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
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60288-2804
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
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~ 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:
3. UT 1.2 (ULs GS) [5~g (~L ~G)/ / L ] +,35 l~ gD
': ` " ' ~
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1 32977 1
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,
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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
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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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