Measuring and testing – Volume or rate of flow – Using differential pressure
Reexamination Certificate
2001-03-21
2003-04-15
Williams, Hezron (Department: 2855)
Measuring and testing
Volume or rate of flow
Using differential pressure
Reexamination Certificate
active
06546811
ABSTRACT:
FIELD OF THE INVENTION
The present invention relates generally to processes, methods, and computer software for calculating mass flow rates of gas and liquid phases of a multiphase flow. More particularly, the present invention relates to software which uses multiple pressure differentials to determine mass flow rates of gas and liquid phases of high void fraction multiphase flows.
PRIOR STATE OF THE ART
There are many situations where it is desirable to monitor multiphase fluid streams prior to separation. For example, in oil well or gas well management, it is important to know the relative quantities of gas and liquid in a multiphase fluid stream, to thereby enable determination of the amount of gas, etc. actually obtained. This is of critical importance in situations, such as off-shore drilling, in which it is common for the production lines of several different companies to be tied into a common distribution line to carry the fuel back to shore. In the prior art, a common method for metering a gas is to separate out the liquid phase, but a separation system in not desirable for fiscal reasons. When multiple production lines feed into a common distribution line, it is important to know the flow rates from each production line to thereby provide an accurate accounting for the production facilities.
In recent years, the metering of multiphase fluid streams prior to separation has achieved increased attention. Significant progress has been made in the metering of multiphase fluids by first homogenizing the flow in a mixer then metering the pseudo single phase fluid in a venturi in concert with a gamma densitometer or similar device. This approach relies on the successful creation of a homogenous mixture with equal phase velocities, which behaves as if it were a single phase fluid with mixture density:
{overscore (&rgr;)}=&agr;&rgr;
g
+(1−&agr;)&rgr;
l
where &agr; is the volume fraction of the gas phase, &rgr;
g
is the gas phase density and &rgr;
l
is the liquid phase density. This technique works well for flows which after homogenizing the continuous phase is a liquid phase. While the upper limit of applicability of this approach is ill defined, it is generally agreed that for void fractions greater than about ninety to ninety-five percent (90-95%) a homogenous mixture is very difficult to create or sustain.
The characteristic unhomogenized flow in this void fraction range is that of an annular or ring-shaped flow configuration. The gas phase flows in the center of the channel and the liquid phase adheres to and travels along the sidewall of the conduit as a thick film. Depending on the relative flow rates of each phase, significant amounts of the denser liquid phase may also become entrained in the gas phase and be conveyed as dispersed droplets. Nonetheless, a liquid film is always present on the wall of the conduit. While the liquid generally occupies less than five percent (5%) of the cross-sectional volume of the flow channel, the mass flow rate of the liquid phase may be comparable to or even several times greater than that of the gas phase due to its greater density.
The fact that the gas and liquid phases are partially or fully separated, and consequently have phase velocities which are significantly different (slip), is problematic where metering of the respective mass flow rates of the gas and liquid phases is concerned. In particular, the presence of the liquid phase distorts the gas phase mass flow rate measurements and causes conventional meters, such as orifice plates and venturi meters, to overestimate the mass flow rate of the gas phase. For example the gas phase mass flow rate can be estimated using the standard equation:
m
g
=
A
C
c
Y
1
-
β
4
2
ρ
g
Δ
P
where m
g
is the gas phase mass flow rate, A is the area of the throat, &Dgr;P is the measured pressure differential, &rgr;
g
the gas phase density at flow conditions, C
c
the discharge coefficient, and Y is the expansion factor. In test samples having void fractions ranging from 0.997 to 0.95, the error in the measured gas phase mass flow rate ranges from about seven percent (7%) to about thirty percent (30%). It is important to note that the presence of the liquid phase increases the pressure drop in the venturi and results in over-predicting the true gas phase mass flow rate. This pressure drop is caused by the interaction between the gas and liquid phases.
In particular, liquid droplet acceleration by the gas, irreversible drag force work done by the gas phase in accelerating the liquid film, and wall losses, determine the magnitude of the observed pressure drop. In addition, the flow is complicated by the continuous entrainment of liquid into the gas phase, the redeposition of liquid from the gas phase into the liquid film along the venturi length, and also by the presence of surface waves on the surface of the annular or ringed liquid phase film. The surface waves on the liquid create a roughened surface over which the gas must flow, thereby increasing the momentum loss due to the addition of drag at the liquid/gas interface.
Other simple solutions have been proposed to solve the overestimation of gas mass flow rate under multiphase conditions. For example, Murdock ignores any interaction (momentum exchange) between the gas and liquid phases and has proposed to calculate the gas mass flow if the ratio of gas to liquid mass flow is known in advance. See Murdock, J. W. (1962),
Two Phase Flow Measurement with Orifices, ASME Journal of Basic Engineering,
December, pp. 419-433. Unfortunately this method still has up to a twenty percent (20%) error rate or higher.
Another example of a multiphase measurement device in the prior art is U.S. Pat. No. 5,461,930, (Farchi et al.), which appears to teach the use of a water cut meter and a volumetric flow meter for measuring the gas and liquid phases. This invention is complicated because it requires the use of a positive displacement device to measure the liquid and gas flow rates so it can avoid the problem of slip between the gas and liquid phases. This system does not appear to be effective for liquid fractions below about five percent to about ten percent (5%-10%). As mentioned earlier, other such prior art systems such as U.S. Pat. No. 5,400,657 (Kolpak et al.), are only effective for multiphase fluid flows where the gas fraction is twenty five percent (25%) of the volume and the liquid is seventy five percent (75%) of the volume.
Other volumetric measuring devices such as are indicated in U.S. Pat. No. 4,231,262 (Boll et al.), measure a flow of solids in a gas stream. For example, coal dust in a nitrogen stream may be measured. Although these types of devices use pressure measuring structures, they are not able to address the problem of measuring a liquid fraction in a multiphase flow where the liquid phase is less than ten percent (10%) or even five percent (5%) of the overall volume. Measuring liquid and gas phases of a multiphase flow is significantly different from measuring a gas having a solid particulate. The mass of the liquid is significant and not uniform throughout the gas. Incorrectly measuring the liquid throws off the overall measurements significantly. Furthermore, such devices, which typically have two pressure measuring points on the venturi throat, are not sensitive to the fact that a pressure drop is caused by the interaction between the gas and liquid phases and must be calculated for accordingly.
While past attempts at metering multiphase fluid streams have produced acceptable results below the ninety to ninety five percent (90-95%) void fraction range, they have not provided satisfactory metering for the very high void multiphase flows which have less than five to ten percent (5-10%) non-gas phase by volume. When discussing large amounts of natural gas or other fuel, even a few percentage points difference in the amount of non-gas phase can mean substantial differences in the value of a production facility.
For example, if there are two wells whi
Bechtel BWXT Idaho LLC
Thompson Jewel V.
Williams Hezron
Workman & Nydegger & Seeley
LandOfFree
Multiphase flow calculation software does not yet have a rating. At this time, there are no reviews or comments for this patent.
If you have personal experience with Multiphase flow calculation software, we encourage you to share that experience with our LandOfFree.com community. Your opinion is very important and Multiphase flow calculation software will most certainly appreciate the feedback.
Profile ID: LFUS-PAI-O-3091206