Multiphase flow measurement (MPFM) is accomplished by using a system of devices that reports the volume or mass of oil, water and gas, generally at some standard process condition of temperature and pressure. The various forms of multiphase flow measurement include a three-phase vessel that separates oil water and gas flow streams, or a vessel that separates gas and liquid flow streams and measures the liquid water cut, or newer technology that replaces the vessel with a smaller lighter flow measurement device. This device is called a multiphase flow meter which is sometimes given the acronym “MPFM.”
The existing forms of multiphase flow measurement typically require a pressure vessel that occupies a large volume, has a high wet weight, has a large footprint and costs a relatively large amount of money. Furthermore, vessels require periodic maintenance of cleaning, painting, device calibration, divert valve leakage testing and control valve maintenance. The newer MPFM technologies may weigh in the range of 2000 to 4000 pounds (907 1814 kg), have a footprint of less than 30 ft² (2.8 m2) and a height of generally no more than 9 feet (2.7 m). If the newer MPFM technology is shown to be equivalent to separation measurement then a weight and space improvement can be realized. Depending on the pricing and trending capability of the new technology it would be feasible to have a MPFM on each well. The pricing of these MPFM’s is highly dependent on the size and range of the meter, the uncertainty, whether it uses a gamma radiation source and other items. The one common item among all MPFM’s is they have to be “calibrated (verified in place)”.
For allocation measurement using a vessel the test duration may be anywhere from 8 to 24 hours. Some of that time is to allow operations to perform other tasks while the tests are proceeding. Multiphase meters require no retention time during operation, typically measuring instantaneously every second which provides a flowing profile over time that is not available using a vessel-type flow measurement system. Slugging and other well performance patterns are readily seen in the output of a MPFM.
These MPFMs determine the instantaneous, incremental gas volume fraction, the water cut and mass or volume rates many times per second. Water cut measurement requires knowledge of oil volume, water volume and salinity plus oil and water density. All MPFM vendors have their own special purpose instrumentation along with off-the-shelf process instrumentation like temperature, pressure and differential pressure instruments. All vendors also have their own empirically derived equations that are solved using fast computers. Some vendors use gamma radiation devices for density and water cut, some vendors use a specialized 0 to 100% water cut meter, some vendors use a venturi for rate, some vendors use mathematical cross-correlation for rate. Some vendors partially separate some of the gas from the flow stream. This would be called a partial separation multiphase flow meter.
What are the issues with multiphase measurement besides an infinite number of instantaneous flow regime scenarios and the fact that most systems must be site calibrated?
The main issues with multi-phase measurement are the multiple and varied fluid properties and flow regime present at the point of measurement. The flow regime is a function of how much oil, water and gas is flowing either vertically, horizontally or slanted, the water salinity, water cut (WC), the oil, water and gas densities, the fluid viscosities, particle sizes, surface tensions and others with flow regimes changing in fractions of seconds. Existing, externally mounted instrumentation such as pressure, temperature, differential pressure, permittivity, and conductivity did not provide all the low uncertainty, instantaneous data required to measure the three phases at low average uncertainties over all conditions of velocity, water cut and gas volume fraction.. Instrumentation and software development is ongoing and improving and provides lowered MPFM uncertainties in larger ranges.
One of the ways to represent the multiphase measurement task is to plot the multiphase measurement requirements on a chart of actual superficial gas rate versus actual superficial liquid rate overlaid with lines of constant GVF (Gas Volume Fraction). These graphs may be on either Cartesian or log-log coordinates. Actual testing of multiphase meters in multiple, precise flow loops in the world has shown that for a given type of multiphase meter uncertainty profiles depend on the meter’s technology and the fluid types and rates. Water cut is represented as the third dimension or z-axis to the gas and liquid coordinates.
Actual testing of multiphase meters has shown that fluid rate uncertainties are a function of water cut, salinity, density and GVF. WC uncertainty tends to increase as the water cut falls below 3 to 6% or is greater than 95%. WC uncertainty may also tend to increase in the range where liquid changes from oil continuous to water continuous phase. Both issues are affected by GVF at the point of measurement.
One common, good characteristic of multiphase meters is repeatability per well but each well might be different. Even though rate uncertainties may be high for a given flow stream, repeatability may be 1% or less. In fact, some meter vendors specify repeatability over uncertainty allowing MPFM data to be very trendable.
Older, more mature production tends to have lower gas volume fractions (in the range of 20 – 50%) which is generally easier to measure with an MPFM. However, MPFM’s are relatively expensive (but costs are coming down); consequently, less complex equipment and technology is often used. Examples are Accu-flo and the GLCC (Gas-Liquid Cylindrical Cyclone compact separator) based systems. These systems separate gas and liquid then use single phase technologies to measure oil, water and gas.
Some secondary production methods such as gas lift causes the produced gas volume fraction to be in the range of 85 to 95% which falls more or less in the general area of “slugging” flow, which in the past has been problematic for full range MPFM’s. “Wet gas” production is normally defined as having a gas volume fraction greater than 95% which with today’s MPFM technology has spawned either meters designed for this range or options for a more traditional full range MPFM with high end options.
Establishing MPFM Requirements:
Let’s cover the ranges of flow measurement requirements that may be found in oil and gas production which may be illustrated by a GVF map. The map has actual gas rates along the horizontal and actual liquid rates along the vertical. If plotted as a rectangular plot, Figures 1 and 2, the lines of constant GVF run upper right to lower left with the lowest GVF on the bottom and the highest on the top. If plotted on log-log coordinates, Figure 3, the constant GVF lines run in parallel increasing left to right. Also, notice for the log-log plot that as GVF increases the constant GVF lines move further apart.
The variation of fluid properties such as viscosity, salinity, particle size and others from well to well helps to explain why an MPFM may work well on one well and not on another even though the rates are very similar.
Figure 1. Variation of actual liquid rate with actual gas rate and gas volume fraction (full GVF range)
Figure 2. Variation of actual liquid rate with actual gas rate and gas volume fraction (high GVF range)
Figure 3. Variation of actual liquid rate with actual gas rate and gas volume fraction (log scale)
General MPFM Measurement Process:
Resolving a multiphase flow stream into oil, water and gas depends on gas density, oil and water density,watercut, conductivity, salinity, capacitance and particle size which may be measurable and effects of flowing viscosity, electrostatic attraction, acid gasses and flow orientation which typically are not measurable.
For most MPFMs it is required to determine the GVF followed by the liquid density or watercut followed by the mass or volumetric rate of each fluid. These iterative, proprietary, calculations are completed at about 30-40 per second on fluid moving anywhere from about 1 m/s to > 30 m/s (3.3 ft/sec to > 98 ft/sec). It is very difficult to describe turndown or rangeability of MPFM systems due to the multiple interactions but may be expressed in terms of each phase.
1. Flowing total fluid density:
Single energy gamma densitometer or a dual acting venturi provides instantaneous flowing fluid density as a function of undetermined gas volume fraction and water cut.
The instantaneous liquid density is highly dependent on instantaneous oil mass or volume rate and density plus the instantaneous mass or volume rate of water and water’s salinity at the instant of measurement.
2. Water-cut is a function of electrical properties as well as water-oil volumes and oil water continuous phase condition:
The measurement of WC uses the electrical property of oil and water called permittivity. There is about a 30:1 to 40:1 permittivity ratio of water to oil but when the fluid is in the water continuous phase conductivity (resistance) is added which almost always affects the measurement. Watercut becomes an iterative solution. If water cut is missed all other calculations are thrown off. When gas is added to oil-water it decreases the average permittivity making the MPFM report more oil.
Water cut or water liquid ratio (WLR) is the volumetric ratio of water volume to total liquid volume:
3. GVF is gas volume to total fluid volume fraction at process conditions:
It is equal to gas void fraction if there is no “Hold-up” or “Slip” between phases.
4. Gas liquid ratio (GLR) is the ratio of actual gas volume (rate) to total liquid volume (rate): 
5. The homogeneous (no slip) relation between GVF and GLR:
One of the ongoing issues with multiphase measurement is whether the assumption that “Slip” is 0 (all phases are flowing at the same velocity) is valid for all flow regimes. Some vendors are now evaluating the flow stream cross section thousands of times per second using technology such as scanning sonar that infers fluid properties. PVT analysis is also applied or sampled properties are hand loaded. Some blind testing has shown that at least for one MPFM the measured properties did better than the PVT calculated properties. Direct measurement of salinity is showing promise both as an instrument and in helping to reduce the measurement uncertainty.
The multiphase measurement system has to solve for gas volume fraction, watercut and fluid volumetric or mass velocity depending on different methods (Table 1).
Table 1: General methods for measuring multiphase flow variables
New instrumentation in MPFM technology better discern instantaneous oil/water/gas fractions: Here is a summary extracted from thesis by Da Silva [1].
1. Complex permittivity needle probe: This technology can detect the phases of a multiphase flow at its probe tip by simultaneous measurement of the electrical conductivity and permittivity at up to 20 kHz repetition rate.
2. Capacitance wire-mesh sensor: This newly developed technology can obtain two-dimensional images of the phase distribution in pipe cross-section. The sensor can discriminate fluids withdifferent relative permittivity (dielectric constant) values in a multiphase flow and achieve frame frequencies of up to 10,000 frames per second.
3. Planar array sensor: The third sensor can be employed to visualize fluid distributions along the surface of objects and near-wall flows. The planar sensor can be mounted onto the wall of pipes or vessels and thus has a minimal influence on the flow. It can be operated by a conductivity-based as well as permittivity-based electronics at imaging speeds of up to 10,000 frames/s.
All three sensor modalities have been employed in different flow applications which are discussed in Da Silva thesis [1].
Electrical Impedance Methods (Capacitance and Conductance):
Impedance methods have attracted a great deal of interest due to their non-invasive instrumentation and almost instantaneous dynamic response. Electrical impedance methods operate by characterizing the multiphase fluid flowing through a pipe section as an electrical conductor. Either contacting or non-contacting electrodes are employed to quantify the electrical impedance across the pipe diameter of the multiphase flow line thus enabling determination of the capacitance or conductance of the fluid mixture. The frequency of the input signal determines whether the measurement is in the impedance or the capacitance mode. By measuring the electrical impedance across two electrodes, the measured resistance and capacitance can be calculated, Blaney [2].
The technical and economical advantages of MPFMs are behind the increasing number of MPFM field installations worldwide in recent years. In addition, some of the major operators have made multiple orders of up to 40 MFMSs for full-field application. Figure 4a shows the actual trend up to and including 1999 plus a 2000 forecast published in 1997 [3]. Figure 4b presents the regional distribution of MPFM installed during 1994-2004 worldwide [4]. Figure 4c presents the total number of MPFM installed up to 2010 and estimated forecast beyond 2010. Based on Figure 4c, an extrapolation for the next 5-10 years of MPFM installations suggests that the number of MPFM installation may double from 2010 estimate [4].
Figure 4a. Growth rate of MPFM installations [3].
Figure 4b. Approximate distribution of MPFM installations worldwide.
Figure 4c. MPFM installation and estimated growth forecast [4]
Summary:
In summary, multiphase measurement flowmeters became possible with fast computer processors. Virtually all MPFM devices utilize proprietary software solutions combined with a combination of proprietary and off the shelf instrumentation. Recent blind tests suggests that measuring fluid properties instead of PVT calculated properties provided improved certainty. The final observation is that proving an MPFM after installation may only require calibrating instruments or quite like proving gas orifice meters.
To learn more about similar cases and how to minimize operational problems, we suggest attending ourIC3 (Instrumentation and Controls Fundamentals for Facilities Engineers), G4 (Gas Conditioning and Processing), G5 (Practical Computer Simulation Applications in Gas Processing) and G6 (Gas Treating and Sulfur Recovery) courses.
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