Metering of two-phase fluids using flow homogenizing devices and chemicals

A two-phase fluid is metered by injecting a surfactant into the two-phase fluid, homogenizing the fluid and surfactant with either a porous medium or an orifice plate to form a pseudo-single phase fluid, and metering the pseudo-single phase fluid. In one embodiment, both the injection of surfactant and the homogenization with either a porous medium or an orifice plate occur within one foot of where the pseudo-single phase fluid is metered. In another embodiment, the surfactant is injected at a wellhead and the metering occurs downhole.

The present invention relates to the metering of two-phase flow (e.g., 
air-water, hydrocarbon gas-condensate, or wet steam). One application of 
the present invention is the metering of two-phase flows in surface 
pipelines. Another application is determining the locations and amounts of 
two-phase fluids leaving injection wellbores (e.g., steam injection 
profiling). In both of these applications, one needs to know both the 
total flowing rate and liquid volume fraction of the two-phase fluid. 
BACKGROUND OF THE INVENTION 
The dynamics of two-phase gas-liquid flow in pipes can be very complicated. 
Differences in the liquid and vapor densities and velocities create 
two-phase flow patterns or regimes, as shown in FIG. 1. These flow regimes 
can range from homogeneous bubble or mist flow to stratified flow to 
intermittent slug flow. The occurrence of a particular flow regime depends 
upon the amount of gas and liquid present in the pipe, their velocities, 
densities, and viscosities. Additionally, the flow regime can vary along 
the length of the pipe as a result of mass transfer between the vapor and 
liquid phases, as is the case when heat loss occurs in steam pipelines. 
The fluid dynamics created by such two-phase flow regimes make it very 
difficult to apply conventional single-phase metering methods reliably and 
accurately. 
SURFACE METERING 
The most straightforward method of determining total flowing rate and 
liquid vapor mass of a two-phase fluid is to measure the individual flow 
rates of the gas (vapor) and liquid phases. To date, the most reliable 
method of measuring the gas and liquid flow rates is to use a separator 
vessel designed to allow nearly complete segregation (over 98%) of the 
phases. The liquid will segregate to the bottom of the vessel, while the 
gas will segregate to the top of the vessel and conventional single-phase 
meters are used to determine the flow rates of the individual phases. 
Examples of conventional single-phase flow rate meters are orifice plates, 
turbines, and vortex shedders. Unfortunately, separators can be very 
costly to build and operate, and they require special manifolding and 
valving to install in a pipeline. 
Recently, methods using an orifice or nozzle in series with a second 
device, such as a critical flow choke or densitometer, have been 
introduced for metering two-phase steam flows in surface pipelines. 
Although orifices and nozzles are commonly used to meter single phase 
fluids (e.g., gas, superheated steam), severe problems can occur when they 
are used to meter two-phase gas-liquid flows. The flow of segregated and 
intermittent mixtures (e.g., stratified, annular, and slug regimes) can 
dramatically affect pressure drop and greatly reduce the reliability and 
accuracy of the orifice meter results. 
Examples of flow regime effects on pressure drop across an orifice are 
shown in FIG. 2 for air-water flows through a one inch Plexiglass pipe 
with a half inch orifice diameter. Large fluctuations in the pressure drop 
occur as a result of intermittent flow of water and air through the 
orifice. These fluctuations are most severe for annular and slug flow, 
where water slugs, at or near air velocity, periodically flow through the 
orifice. Conversely, the pressure drop caused by the flow of distributed 
or homogeneous mixtures through an orifice should be stable, since these 
flows are nearly single-phase. Previous attempts to homogenize two-phase 
gas-liquid flows have used mechanical devices installed upstream of 
metering devices. However, numerous studies have shown that the gas and 
liquid phases separate immediately upon leaving the homogenizing device. 
WELLBORE PROFILING 
Spinner and radioactive tracer surveys are the current methods used to 
obtain two-phase flow profiles in injection wells. These methods are 
routinely used for profiling single-phase water or gas injection and 
production wells. Running and interpreting spinner and tracer surveys are 
not straightforward for single-phase flow conditions, and are much more 
difficult when the complexities of two-phase flow conditions are added. 
Spinner surveys incorporate the use of a turbine that rotates as fluid 
flows past it. In a single-phase flow, the rotation frequency (number of 
revolutions per second) of the turbine is proportional to the flow 
velocity. However, in two-phase flow, the spinner response is sensitive to 
variations in flow regime, which can result in large measurement errors. 
Spinner surveys, in fact, cannot clearly identify profiles for the 
individual gas and liquid phases. 
The radioactive tracer method is less sensitive to changes in flow regime 
and can provide profiling information for both the gas and liquid phases. 
The "Velocity Shot" method is used to determine the vapor flow profile and 
the "Plating" method is used to determine the liquid flow profile. 
The "Velocity Shot" method consists of injecting a fixed amount (slug) of 
radioactive krypton, xenon, or methyl iodide to trace the flowing gas 
phase and recording the transit time of the slug between two downhole 
radiation detectors spaced a fixed distance apart. The dual detector tool 
is then lowered to the next location and another tracer slug is injected, 
and so on. The vapor injection profile is obtained from comparison of the 
transit times at different depths. 
The "Plating" method consists of running an initial survey to determine 
background radiation levels in the wellbore and surrounding reservoir. A 
slug of radioactive substance (e.g., sodium iodide) is injected to trace 
the flowing liquid phase and allowed to plate out in the surrounding 
reservoir. Several surveys are subsequently run over the injection 
interval and the radiation intensity is recorded. The liquid injection 
profile is determined from comparison of changes in the radiation 
intensity over time at different depths. 
However, these methods are not nearly as reliable and accurate for 
two-phase flows as they are for single-phase flows. The gas flow area may 
change across the injection interval as the flow regime changes, resulting 
in additional uncertainties in the gas profile. Liquid profiles obtained 
from the plating method are generally considered to be qualitative, not 
quantitative. 
SUMMARY OF THE INVENTION 
The present invention involves metering a two-phase fluid, such as wet 
steam, by injecting a surfactant into the two-phase fluid to form a 
"pseudo-single phase" fluid, and metering that pseudo-single phase fluid. 
By making a two-phase fluid into a pseudo-single phase fluid, one can 
apply existing single-phase rate metering methods with vapor fraction 
detectors. 
To further the action of the surfactant, a mechanical mixing device may be 
used just upstream of the detection point or the injection sandface. That 
mixing device can be a porous medium, static mixer, or orifice plate. Both 
the surfactant injection and the mechanical mixing should occur within one 
foot upstream of where the pseudo-single phase fluid is metered. 
The present invention overcomes the difficulties mentioned above by turning 
a two-phase fluid into a pseudo-single phase. Once that pseudo-single 
phase is created, single-phase metering devices may be used to determine 
the flow rate and flowing liquid volume fraction accurately. When a 
pseudo-singe phase is injected, the quality of the injected fluid would be 
uniform over the injection interval, and uncertainties associated with 
flow regime effects are greatly reduced. Therefore vapor tracers or 
spinner surveys will indicate the distribution of both liquid and vapor 
injections. 
In one embodiment, the surfactant is injected at a wellhead and the 
metering occurs downhole. In that embodiment, the surfactant and fluid are 
homogenized with a mechanical mixing device at the wellhead.

DETAILED DESCRIPTION OF THE INVENTION 
In its broadest aspect, the present invention involves metering a two-phase 
fluid by injecting a surfactant into the fluid to form a pseudo-single 
phase fluid, and metering the pseudo-single phase fluid. 
By "pseudo-single phase fluid," we mean a two-phase fluid wherein the 
"two-phase" nature of that fluid is sufficiently homogenized so that a 
small sample of the fluid has the same composition and properties of the 
entire fluid. Examples of "pseudo-single phase" fluids are foam and mist. 
By "surfactant," we mean a surface-active substance that alters the surface 
properties of a fluid to which it is added. Such a substance can produce 
foam or other pseudo-single phase fluids when injected into a two-phase 
fluid. Examples of surfactants include alkyl aromatic sulfonates, alpha 
olefin sulfonates and derivatives including dimers, alkyl diphenylether 
disulfonates or sulfonates, alkyl naphthalene sulfonates, and alcohol 
ethoxysulfates. Examples of particular surfactants that would work are 
Chaser CS1010, Chaser SD1000, and Chaser SD1020, which are all trademarked 
products of Chevron Chemical Company, and which have high active 
concentrations (50% active) and the ability to foam at steam injection 
conditions. 
Preferably, when the liquid volume fraction of the two-phase fluid is at 
least 0.05, a "high foaming surfactant" is injected into the two-phase 
fluid to generate foam just upstream of the metering device or near the 
injection sandface. By "high foaming surfactant," we mean a surfactant 
that, when added, alters the surface properties of the two-phase fluid so 
as to produce a foam. Examples of "high foaming" surfactants are Chaser 
SD1000 and Chaser SD1020, which are trademarked products of Chevron 
Chemical Company. 
When the liquid volume fraction of the two-phase fluid is less than 0.03, a 
"less active surfactant" may be used instead, to turn the flowing fluid 
into a mist flow regime. By "less active surfactant," we mean a surfactant 
that, when added to the liquid phase of a two-phase fluid, mainly alters 
the viscosity of the liquid phase, allowing the liquid phase to be 
entrained in the gas phase as small droplets. Examples of "less active" 
surfactants are hydrocarbon solvent or Chaser CS1010, which is a 
trademarked product of Chevron Chemical Company. 
To best form a pseudo-single phase fluid, the surfactant and two-phase 
fluid are homogenized with a mechanical mixing device prior to metering. 
Examples of mechanical mixing devices include porous medium or an orifice 
plate. Preferably, both the injection of surfactant and the homogenization 
with mechanical mixing occur within one foot upstream of where the 
pseudo-single phase fluid is metered so that the fluid will stay 
pseudo-single phase. 
By transforming two-phase flow into a pseudo-single phase flow, one can 
apply conventional single-phase metering methods and vapor fraction 
detection methods to accurately determine flowing rate and liquid volume 
fraction of the two-phase fluid. Examples of such conventional 
single-phase rate metering methods include orifice plates, turbines, and 
vortex shedders. Examples of vapor fraction detection methods include 
vibrating densitometers and radiation detectors. 
When used in surface metering, the surfactant is injected into the pipeline 
upstream of the meter. A mechanical mixing device can be installed 
downstream of the chemical injection and upstream of the metering device, 
or it can be incorporated as part of the metering device. 
Referring to FIG. 3, which shows one embodiment of surface metering, a 
two-phase fluid flows through pipe 10. Surfactant is injected at point 20, 
and the fluid and surfactant is mixed in mixer 30 to form a pseudo-single 
phase. The pseudo-single phase passes through orifice plate 50 and vapor 
fraction detector 90, and the pressure of that pseudo-single phase is 
measured before the orifice plate, at pressure tap 40, and after the 
orifice plate, at pressure tap 60. 
In the application to wellbore profiling, the surfactant is injected at the 
wellhead, while the meter is positioned downhole. A mechanical mixing 
device can be added at the wellhead, downstream of chemical injection. In 
wellbore profiling, it is essential that the two-phase fluid remains 
homogenized at least until it has been metered downhole. 
Referring to FIG. 4, which shows one embodiment of wellbore profiling, a 
two-phase fluid flows through pipe 10. Surfactant is injected at point 20, 
and the fluid and surfactant is mixed in mixer 30 to form a pseudo-single 
phase. The pseudo-single phase is injected into the well, and the 
pseudo-single phase is metered downhole at 70 and distributed into the 
formation 80. The injection profile 35 is determined from downhole 
measurements at 70. 
While the present invention has been described with reference to specific 
embodiments, this application is intended to cover those various changes 
and substitutions that may be made by those skilled in the art without 
departing from the spirit and scope of the appended claims.