01 March 2003
Transducers: Theories for hydrocarbon flow measurement sensors
By Youssef Basrawi
Imagine you're standing in the center of a merry-go-round, rotating with an angular velocity w of 1 revolution per minute. You start to walk at a constant speed from the center to the edge of the merry-go-round. When passing A you are covering the distance A´, and when passing B, you are covering the distance B´—both in the same minute. The distance B´ is much greater than the distance A´. Apparently you have been accelerating. You have a certain mass, and from Newton's second law, force = mass x acceleration, there must be a force. This force and acceleration is named after Coriolis and is the basis for this type of mass flowmeter.
Applying flow sensor to crude and hydrocarbon fluids
Crude and hydrocarbon product measurements come in two types: volumetric and mass flow. Accuracy and precision play a key role in influencing the current applications of volumetric and mass flow measurement technologies when applied to royalty and custody transfers for exports and domestic consumption. The four main flow measurement parameters are as follows:
1) Temperature. The hydrocarbon industry uses filled systems, glass stem, bimetallic, pyrometric devices, temperature-sensitive material, thermocouples, and resistance temperature detectors.
2) Pressure. There are two types of line pressures: static and dynamic. In static pressure, two trends occur. Mechanical links and levers within pressure measuring devices are replaced with silicon-based sensors, such as gravitational gauges and deformation sensors and switches. And microprocessor-based instruments, particularly the smart or intelligent types, are emerging as the preferred instruments: transducers and transmitters. Dynamic pressure sensing instrumentation in flow measurements are microprocessor-based instruments. Differential pressure gives rise to flow, so it would be equally correct now to consider flow sensing instrumentation in the same category. Some of the devices in this category include restriction orifice plates, pitot tubes, annubars, nozzles, venturi, positive displacement, turbine, magnetic, ultrasonic, mass, vortex, and flow variable area flowmeters.
3) Level. Some categories of level devices include sight, float, displacement, force, pressure, electrical, ultrasonic, nuclear, laser, and thermal.
4) Density. Liquid density is one of the many parameters you must accurately measure for product quality control, custody transfer, process control, or liquid interface detection purposes. Some of the densitometers in use today include vibration, buoyancy, nuclear, and acoustic. In the hydrocarbon industry, the vibrating tube densitometer is most common. Each type has advantages and disadvantages. The simplest vibrating system has a spring and is mass mechanically connected. If the mass is displaced and released, the system vibrates at a known frequency. This concept is related to a vibrating tube densitometer. The spring constant is related to the stiffness of the tubing. The mass is related to the mass of the tubing plus the mass of the liquid inside the tubing. As the mass (or density) of the fluid in the tubing varies, the natural frequency varies.
The problem facing the industry today is that ±0.5% of flow measurement error can result in more than $255,150,000 of annual unaccountable revenue—giving away one tanker full of cargo every 1.5 months. The industry's objective is mainly to minimize and control hydrocarbon losses through accurate measurement.
Using transducer technology is one way to do that. Take the merry-go-round analysis. The Coriolis force Fc prevents you from arriving at the point you were originally heading for. The resulting deflection D is a measure of the Coriolis force and, as such, the mass. The faster you walk, the larger the deflection. This type of meter measures the mass of the fluid flowing through vibrating U- or S-shaped tubes. As the fluid flows through the vibrating tubes, the naturally occurring Coriolis force causes a slight rotation of the meter tube about its axis, which is proportional to the amount of mass flowing in the tube. These meters can also measure density as a function of the tube's natural frequency.
The mass meter was tested for two years against standard weigh measures for fluid flow to get a comparison of accuracy and a measure of deviation from acceptable conventional weight equipment as used for mass measurement. The meter showed striking consistency in measurement over the test period. When compared with the weight scale, the standard deviation was 40 kilograms between the fluid mass as measured by the scale and mass meter. This translated to 0.16% standard deviation.
Following are some more examples of flow sensor applications for crude and hydrocarbon fluids, as well as a primer on flowmeters and an explanation of the technology, theory, and application of transducers to flow measurement sensors—the kind used for royalty and custody transfer measurements of crude and hydrocarbon products.
The hydrocarbon industry typically uses orifice plate and helical flowmeters. Of particular interest are the master meter technology in certifying crude and product meter providers, water-in crude detection instrument (under evaluation in the field today), liquid sonic flowmeters as applied in operations and custody flow, and mass flowmeters (as described in the Coriolis mass flowmeter scenario above).
Master meter technology for prover certification
The standard method of calibrating any pipe prover involves determining the volume, displaced between detectors at standard condition (15°C/60°F and 101.325 kilopascal/14.73 pounds per square inch, absolute). Displacer moves from the launch chamber toward the detector switch through the four-way valve. The measured volume—moved by the displacer—starts from the instant the displacer activates the first detector to the instant it contacts the second detector on the other side of the prover. This is called one pass or half trip.
The four-way valve reverses, and the same procedure repeats in the opposite direction for the second pass. Fluid appears in the master meter, master prover, and the prover to be calibrated. Trial runs occur against the master prover or master test measure to calculate its meter factor.
Test findings reveal the master meter calibrated the volume of a 42-inch crude meter prover installed on an offshore platform. The results, compared with the normal conventional method (water draw), showed remarkable accuracy. The difference in volumes between the two methods was 0.2289 U.S. barrels = 2220.79 cubic inch at standard conditions (0 pounds per square inch, gauge, and 60°F). The deviation was 0.05%.
Water cut meter
While the old water cut monitors were lucky if they resulted in accuracies of ±20%, today's instruments can measure the full range (0% to 100%) of water to within ±0.05%. This is as good as the repeatability of laboratory tests used to determine the water content in custody transfer applications. The whole custody transfer process could finally operate remotely.
The dielectric constant and conductivity of water are much higher than that for oil. You can use this difference to measure the water content of oil/water mixtures. The water cut meter measures the microwave dielectric properties of mixtures using the resonant cavity method. The density of a material in the tube affects its natural vibration frequency. By measuring the frequency, you can measure the design of the material.
A resonant cavity is a metal structure, which confines an electric field and causes it to reflect back and forth within the cavity. If the wavelength of the electromagnetic waves equals one of the dimensions of the cavity, the multiple reflecting waves constructively interfere and generate a standing wave: electric field resonance.
If you fill a resonant cavity with a material, the cavity will shift by an amount directly related to the dielectric constant of the material. The width of the resonant peak is related to the conductivity of the material in the cavity. So by measuring the resonant frequency and peak width, you measure the dielectric properties of a material in the cavity.
After 29 tests on wellheads, checking the water monitor's accuracy and consistency compared with gas oil separation plant (GOSP) test traps, the water monitor measured 500–7,500 barrels per day using the GOSP's test trap and 500–4,500 barrels per day using the water monitor for total liquid flow rate. The percent of water in crude results showed 0% to 97% using the GOSP's test trap and 0% to 100% using the water monitor. Of the 29 tests, 26 showed the water monitor measurements were within ±10% of those in the reference test trap. For an acceptable 10% accuracy, the water monitor showed good repeatability. The maximum operating range of the monitor used was 4,500 barrels per day, compared with that of the reference measure: 7,500 barrels per day. Thus, you'll get better accuracy by using the appropriate size meter, especially at the higher flow ranges.
The oil industry mostly uses meters based on the principle of time of flight (transit time). This meter comes in either an external (clamp-on) or spool piece (chordal) configuration. Using a sophisticated technique lets you detect very small time differences and enables you to reach a measuring resolution as low as 1 millimeter. These meters use transducers that excite a natural waveguide mode of a pipe so it induces a sonic wave that travels axially down the pipe wall.
At the same time, sonic energy travels through the liquid in the form of a beam. The beam of energy arrives at the far wall and travels toward the receiver transducer, where it's collected. The ultrasonic flowmeter takes advantage of the principle that an ultrasonic pulse travels faster downstream and slower upstream. The larger the difference in time between the two pulses, the more fluid that passes by. Because ultrasonic meters do not rely on kinetic energy from the fluid, you detect only very low flow rates. This results in a high turndown (typically 50:1) and no pressure drop. If you inject sonic energy alternately in the downstream and upstream directions, and you know the angle of refraction, you can determine a pretty accurate flow rate.
Because the sonic velocity of a liquid is a function of its density, you can determine its density and viscosity. The current accuracies of liquid ultrasonic meters and the improvements in electronics and temperature and density compensation techniques have earned these types of meters equal partner rights in the custody transfer process. Given their relatively maintenance-free operation, you could reduce manpower costs related to maintenance. These meters are capable of batch tracking and detecting interface, making them attractive for custody transfers.
The chordal and clamp-on sonic meters tested with fluid velocity at 40 feet per second. The chordal meters showed ±0.25% accuracy, and the clamp-on showed ±0.15% accuracy. Both showed turndown ratios of 300:1. FT
Behind the byline
Youssef F. Basrawi is a flow measurement specialist at Saudi Aramco (Saudi Arabian Oil Co.) in Dhahran, Saudi Arabia.
Return to Previous Page