Measuring and testing – Volume or rate of flow – Using differential pressure
Reexamination Certificate
1999-09-22
2003-01-07
Fuller, Benjamin R. (Department: 2855)
Measuring and testing
Volume or rate of flow
Using differential pressure
Reexamination Certificate
active
06502467
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to a flow meter for measuring the flow of very high void fraction multi-phase fluid streams. More particularly, the present invention relates to an apparatus and method in which multiple pressure differentials are used to determine mass flow rates of gas and liquid phases of a predominantly gas fluid stream to thereby determine the mass flow rate of each phase.
2. State of the Art
There are many situations where it is desirable to monitor multi-phase 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 multi-phase 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 multi-phase fluid streams prior to separation has achieved increased attention. Significant progress has been made in the metering of multi-phase 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, and &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 may be comparable to or even several times greater than that of the gas phase due to its greater density.
The fact that the phases are partially or fully separated, and consequently have phase velocities which are significantly different (slip), complicates the metering problem. The presence of the liquid phase distorts the gas mass flow rate measurements and causes conventional meters, such as orifice plates or venturi meters, to overestimate the flow rate of the gas phase. For example the gas mass flow can be estimated using the standard equation
m
g
=
AC
c
Y
1
-
β
4
2
ρ
g
Δ
P
where m
g
is the gas mass flow rate, A is the area of the throat, &Dgr;P is the measured pressure differential, &rgr;
g
the gas density at flow conditions, C
c
the discharge coefficient, and Y is the expansion factor. In test samples using void fractions ranging from 0.997 to 0.95, the error in the measured gas mass flow rate ranges from 7% to 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 mass flow rate. The pressure drop is caused by the interaction between the gas and liquid phases. 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, the redeposition of liquid from the gas 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 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 multi-phase conditions. For example, Murdock, ignores any interaction (momentum exchange) between the gas and liquid phases and 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, 419-433. Unfortunately this method still has up to a 20% error rate or more.
Another example of a multi-phase measurement device in the prior art, is U.S. Pat. No. 5,461,930, to 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 must use 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 (5%-10%). As mentioned earlier, other such prior art systems such as U.S. Pat. No. 5,400,657 to Kolpak, et al, are only effective for multi-phase fluid flows where the gas fraction is 25% of the volume and the liquid is 75% of the volume.
Other volumetric measuring devices such as U.S. Pat. No. 4,231,262 to 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 multi-phase flow where the liquid phase is less than 10% or even 5% of the overall volume. Measuring a liquid and gas is significantly different from measuring a gas with 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 have two pressure measuring points on the venturi throat, do not take into account 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 multi-phase 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 multi-phase flows which have less than five to ten (5-10%) non-gas phase by volume. When discussing large amounts of natural gas or other fuel, even a few percent 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 which produce equal amounts of natural gas per day. The first well produces, by volume, 1% liquid and the second well produces 5% liquid. If a conventional mass flow rate meter is relied upon to determine the amount of gas produced, the second well will erroneously appear to produce as much as 20-30% more gas than the first well. Suppose further that the liquid produced is a light hydrocarbon
Bechtel BWXT Idaho LLC
Fuller Benjamin R.
Thompson Jewel V.
Workman & Nydegger & Seeley
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