D. Tamboli, The NEWTRON Group, Reno, Nevada
Flare gas meters are used in facilities such as oil rigs, refineries and chemical plants to measure the gas flows in flare lines. In many parts of the world, this is a regulatory requirement. Several technologies are available to measure the flow of gas—these technologies are based on different physical principles and have their own performance characteristics with advantages and disadvantages.
Flare gas flowmeters provide plant operations managers with an intelligent tool to signal abnormal process changes, detect leaks early and report on flared gases to comply with safety and environmental agency reporting (FIG. 1). In their efforts to reduce global warming, the U.S. Environmental Protection Agency (EPA), the European Union (EU) and agencies at multiple levels of governments around the globe are imposing stricter regulations that vary by geographic zone for air pollution monitoring, abatement and reporting.
Many oil and gas operators, refineries and chemical plants have flare gas system applications that are uniquely challenged with three diverse and critically important flow conditions:
Plant operators, managers and instrument-and-control engineers are then further challenged to comply with environmental agencies and emissions trading regulations for their flares stipulating flowmeter accuracy of approximately ±5% throughout the entire measuring range.1,2
Flowmeter challenges. Flare gas flow measurement applications present several unique challenges to plant, process and instrument engineers when selecting a flowmeter solution. In addition to both low flowrates and then sudden high flowrates during upset conditions, several other important criteria must be considered when selecting a flowmeter for flare gas applications:
Key criteria for flowmeter selection. When selecting a flowmeter for flare gas applications, plant operators, managers, and process and instrument engineers must compile a key criteria checklist. There are multiple air/gas flow measurement technology choices, but not all of them are well suited to the accuracy, reliability and rangeability required by the rugged operating environment in the oil/gas industry. For example, some flowmeter technologies are better at measuring volume than mass flow.3 The accuracy of some flowmeters is influenced by heat and some sensor technologies are temperature-compensated to maintain accuracy. Moving parts are acceptable in some operating environments; in other environments, they can require high levels of maintenance, repair or replacement.
Selecting a flowmeter can be a complicated process. A checklist to select a flare gas flowmeter should include (at a minimum) the capabilities listed below. Creating a simple check-box matrix to compare various flowmeters against the following criteria will quickly narrow the choices:
Differential pressure (DP) measurement. DP meters work on the principle of partially obstructing the flow in a pipe. This creates a difference in the static pressure between the upstream and downstream sides of the device. This difference in the static pressure (referred to as the DP) is measured and used to determine the flowrate.4,5
The basic principle of DP flowmeter operation is described in FIG. 2.
Manometer tubes measure the difference in static pressure upstream and downstream of the restriction.
When a fluid flows through a restriction, it accelerates to a higher velocity (i.e., V2 > V1) to conserve the mass flow and, consequently, its static pressure drops. This DP (Δp) is then a measure of the flowrate through the device.
The relationship between the DP and flowrate is derived from Bernoulli’s equation. Using Bernoulli’s equation, and the conservation of mass, it can be shown that the DP generated is proportional to the square of the mass flowrate, Qm (kg/sec).
Overall, DP meters offer a rugged design that can withstand harsh process conditions and tolerate the presence of some liquids. Their main disadvantages are their limited operating range and the flow resistance they introduce, which, for vent and flare gas measurements, tend to exclude them from use on pressure relief systems. Additionally, while they have no moving parts, maintenance can be intensive. Accuracy, under well-behaved conditions, ranges from within ±1% to ±5% of full scale. Compensation techniques can improve accuracy to within ±0.5% to ±1.5% of full scale.
Density corrections are applied to the results based on the composition and absolute temperature and pressure of the fluid. The American Gas Association (AGA) provides detailed procedures, AGA-3 or American Petroleum Institute (API)-2530/ISO-5167, for performing these calculations. Modern DP meters feature an onboard flow computer for performing these calculations.
Key limitations include:
Orifice and venturi meters are the most common style of DP flowmeter. These inline flowmeters are the most widely used technology for measuring gas flows in upstream oil and gas production accounting applications. They can be used to measure fluid flow in pipes with diameters of approximately 1.3 cm–180 cm (0.5 in.–72 in.).
Orifice meters. The orifice plate consists of a flat circular plate with an outer diameter greater than the inner diameter of the measuring fluid pipe and a thickness of ≥ 3 mm, as per the line pressure and material used. As indicated in FIGS. 3 and 4, a circular (or a circular segmental) hole is drilled in it which may not be centrally located in, for example, an eccentric orifice plate.
As the fluid approaches the orifice, the pressure increases slightly and then drops suddenly as the orifice is passed. As the pressure decreases steadily until it reaches the "vena-contracta," (the narrowest point of the jet), it then begins to gradually rise again. This upward trend persists until approximately 5 to 8 times the downstream diameter, where it reaches a peak pressure point. However, it is worth noting that this maximum pressure point remains lower than the pressure upstream of the orifice.
The decrease in pressure as the fluid passes through the orifice is a result of the increased velocity of the gas passing through the reduced area of the orifice.
When the velocity decreases as the fluid leaves the orifice, the pressure increases and tends to return to its original level. All the pressure loss is not recovered due to friction and turbulence losses in the stream. The pressure drop across the orifice increases when the rate of flow increases. When there is no flow, there is no differential.
The DP is proportional to the square of the velocity; therefore, it follows that if all other factors remain constant, then the differential is proportional to the square of the rate of flow.
The rangeability of the orifice meter is less than 5:1, and accuracy—even under ideal conditions—is moderate at ±2% to ±4% of full scale. Maintenance of good accuracy requires a sharp edge to the upstream side of the orifice plate. This edge will wear and degrade over time.
Pressure loss for orifice plates is high relative to other types of DP elements.
Orifice plates are sensitive to the build-up of valve lubricant or other coating material and should be checked. A ¼-in. build-up can introduce errors of up to ~30%. Plates should also be checked for warping (a ¼-in. warp can introduce up to 10% error).
Venturi meters. Venturi meters comprise a converging nozzle and a diverging nozzle. They offer increased durability and accuracy compared to an orifice meter, but their operating range is fixed for the specified process conditions (FIG. 5). Pressure loss is low, making it a good choice when little pressure head is available.
Their rangeability, while better than orifice plates, is less than 6:1, with an accuracy of within ±1% to ±2% of full scale under ideal conditions. Flow must be turbulent (i.e., with a Reynolds numbers > 10,000).
Venturi flowmeters are widely used for wet gas applications that involve measurement prior to any form of separation or fluid processing. Their advantages include:
Averaging pitot tubes (Annubar). An Annubar flowmeter (FIG. 6)—also referred to as an averaging pitot—has multiple vented ports on its upstream side ( i.e., the higher pressure side) that all lead to a single pressure tapping point. This means the pressure tapping point receives an average upstream pressure.
The upstream ports are blocked from the downstream port by a barrier in the tube. The downstream port is connected directly to a downstream pressure tapping point.
The averaging pitot tube acts as a partial obstruction to the fluid flowing. Flow around this obstruction causes a DP to form between the upstream and downstream sides of the tube. This DP is proportional to the square of the velocity of the fluid in the pipe, in accordance with Bernoulli’s theorem.
The rangeability is 3:1, and pitot tube accuracies vary from ±0.5% to ±5% of full scale under ideal conditions. The benefit of averaging pitot tubes is that they measure average across the pipe rather than at one point. They are also a relatively inexpensive option.
Averaging pitot tubes are not an ideal solution for flare gas measurement, however, because they measure volumetric flow rather than mass flow. That key difference can impact the accuracy required to meet key government regulations. Averaging pitot tubes are also highly prone to clogs and other issues since they are exposed directly to the gas flow. They have poor high- and low-flow (turndown) capabilities and are unable to measure changes in gas composition changes.
Vortex flowmeter. A vortex meter, shown in FIG. 7, is a type of volumetric flowmeter that makes use of a natural phenomenon that occurs when a liquid flows around a bluff object. Vortex flowmeters operate under the vortex shedding principle, in which vortices (or eddies) are shed alternately downstream of the object. The frequency of the vortex shedding is directly proportional to the velocity of the liquid flowing through the meter.
Theodor von Karman, while fishing in the mountain streams of the Transylvanian Alps, discovered that, when a non-streamlined object (also called a bluff body) is placed in the path of a fast-flowing stream, the fluid will alternately separate from the object on its two downstream sides, and, as the boundary layer becomes detached and curls back on itself, the fluid forms vortices (also called eddies or whirlpools). He also noted that the distance between the vortices was constant and depended solely on the size of the object (e.g., rock) that formed it. On the side of the bluff body where the vortex is being formed, the fluid velocity is higher and the pressure is lower. As the vortex moves downstream, it grows in strength and size and eventually detaches or sheds itself. This is followed by a vortex being formed on the other side of the bluff body. The alternating vortices are spaced at equal distances.
Bluff body shapes (e.g., square, rectangular, t-shaped, trapezoidal) and dimensions have been experimented with to achieve the desired characteristics. Testing has shown that linearity, a low Reynolds number limitation and sensitivity to velocity profile distortion vary only slightly with bluff body shape. In size, the bluff body must have a width that is a large enough fraction of the pipe diameter that the entire flow participates in the shedding. Second, the bluff body must have protruding edges on the upstream face to fix the lines of flow separation, regardless of the flowrate. Third, the bluff body length in the direction of the flow must be a certain multiple of the bluff body width.
Today, most vortex meters use piezoelectric or capacitance-type sensors to detect the pressure oscillation around the bluff body. These detectors respond to the pressure oscillation with a low-voltage output signal with the same frequency as the oscillation. Such sensors are modular, inexpensive, easily replaced and can operate over a wide range of temperature ranges—from cryogenic liquids to superheated steam. Sensors can be located inside the meter body or outside. Wetted sensors are stressed directly by the vortex pressure fluctuations and are enclosed in hardened cases to withstand corrosion and erosion effects.
External sensors, typically piezoelectric strain gages, sense the vortex shedding indirectly through the force exerted on the shedder bar. External sensors are preferred on highly erosive/corrosive applications to reduce maintenance costs, while internal sensors provide better rangeability (better flow sensitivity). They are also less sensitive to pipe vibrations. The electronics housing is usually rated explosion and weatherproof and contains the electronic transmitter module, termination connections and optionally a flowrate indicator and/or totalizer.
Vortex meters are not usually recommended for intermittent flow applications because the dribble flowrate setting of the batching station can fall below the meter's minimum Reynolds number limit.
Low-pressure (low-density) gases do not produce a strong enough pressure pulse, especially if fluid velocities are low. Therefore, it is likely that in such services the rangeability of the meter will be poor and low flows will not be measurable.
If the process fluid tends to coat or build up on the bluff body, as in sludge and slurry service, this will eventually change the meter's K factor. Vortex-shedding flowmeters are not recommended for such applications.
When measuring multi-phase flow (solid particles in gas or liquid; gas bubbles in liquid; liquid droplets in gas), vortex meter accuracy will drop because of the meter's inability to differentiate between the phases.
The main advantages of vortex meters are their low sensitivity to variations in process conditions, low wear, and low initial and maintenance costs. For these reasons, they have been gaining wider acceptance across industries.
Thermal mass flowmeter. A thermal mass flowmeter (shown in FIG. 8), also known as a thermal anemometer, uses a combination of heated elements and temperature sensors to measure the difference between static and flowing heat transfer in the gas, which will be used to measure the flow. However, this requires a knowledge of the thermal properties and density of the gas. In either case, the heat loss or cooling effect due to fluid convection is a function of the fluid velocity.
The thermal conductivity and specific heat of the fluid are assumed to be constant. Changes in density cause calibration shifts, and the coating of the sensor can cause drift.
Thermal mass flowmeters are highly sensitive to the presence of liquids or condensation in the gas stream and, therefore, are not appropriate for use in applications involving wet or condensing gases (e.g., treater or stabilizer overheads, flash gas or tank vapors). Additionally, they tend to have more stringent temperature limitations than most other types of flowmeters.
These meters are calibrated at the factory to air or one of a limited number of other gas options offered by the manufacturer (e.g., methane). Features are not provided for routinely correcting the readings for compositional differences between the reference fluid and the actual fluid. Consequently, for quantitative flow measurement, their use is limited to applications involving a relatively consistent gas composition, like the reference calibration gas. Otherwise, the meter simply provides an indication of the relative changes in flow rather than an accurate reading of the amount of flow.
Limitations include:
Thermal mass flowmeters have fast response times and rangeabilities of up to 1,000:1 when flow-calibrated using air or methane. They do, however, require significant correction for changes in gas composition. Accuracy levels typically range from ±1% to ±3% of the reading under ideal conditions.
However, new advancements in thermal gas flowmeter technology have overcome some of the obstacles like field calibration with actual gas compositions, etc., making them one of the viable solutions for flare gas measurement.
Transit-time ultrasonic flowmeter. Ultrasonic flowmeters are the most common volumetric flow measurement device. Many types of ultrasonic flowmeters are available, including transit-time flowmeters, doppler flowmeters, cross-correlation flowmeters, phase-shift flowmeters, drift flowmeters, etc. Transit-time ultrasonic flowmeters are a widely used and advanced state-of-the-art measurement technology.
This type of meter determines flow velocity by measuring the transit time required for an ultrasonic pulse to travel through the flow between two fixed transducers usually positioned diagonally across the pipe diameter (FIG. 9). Two sets of transit time measurements are performed, one with the wave traveling with a positive flow component and one in the reverse direction resulting in a negative flow component. This information can then be used to solve for the path-integrated flow velocity and the speed of sound in the gas. The differential transit time is directly proportional to the flow velocity of the gas, i.e., the higher the gas flow velocity, the higher the differential time will be.
The instrument applies its own correction factor to convert the path-integrated flow velocity to an average flow velocity that can then be used to determine the flowrate for the given pipe diameter. Velocities as low as 0.03 m/sec (0.1 ft/sec) and as high as 100 m/sec (328 ft/sec) can be measured. Accuracies range from ±2% of the measured value up to 25 m/sec and ±5% of the measured value from 25 m/sec–100 m/sec. Rangeabilities up to 2,000:1 may be achieved.
The transducers must be wetted to the flow (i.e., inserted through the pipe wall and brought into direct contact with the flowing fluid) to launch a strong enough ultrasonic pulse to stand out above normal flow noise. The transducers do not need to extend into the flow, so they do not introduce any pressure drop. To ensure proper alignment and positioning, the transducers are normally installed on a spool piece at the factory, which is then installed as an inline flowmeter (FIG. 10).
Ultrasonic flowmeters are the preferred choice in most permanent vent or flare applications involving wet and dirty gas, provided the liquid content does not exceed ~0.5 vol%. Ultrasonic flowmeters offer excellent rangeability, good accuracy, do not require frequent calibration, are not composition dependent, and do not pose a significant flow restriction. If greater amounts of liquids are anticipated, then a liquids knockout system should be installed immediately upstream of the flowmeter.
Ultrasonic flowmeters also perform well for conditions involving extreme fluctuations in temperature and pressure. They have no internal parts that can drift and cause inherent errors. Calibration needs are greatly reduced compared to other flowmeters that have compositional dependencies or are susceptible to fouling, such as orifice meters and insertion flowmeters. Although not necessary for normal flare and vent applications, transit-time ultrasonic flowmeters also determine flow direction.
The speed of sound result can be used to estimate the molecular weight of the gas by assuming perfect gas behavior. This information can be used to help identify the source of the flare gas on emergency flare systems.
Another important feature of ultrasonic flowmeters is that they can measure the mass flow after the molecular weight or density compensation rather than the volumetric flow, providing more accurate readings through factors like temperature changes.
On the downside, the entire meter must be removed if pipe sections need to be cleaned. This process can lead to accuracy problems over time. Swirl and other flow profile effects can also influence the accuracy of ultrasonic flowmeters.
Lastly, ultrasonic flowmeters are an expensive solution. These meters compute flowrates using multiple paths, with more paths translating to better measurements. Each of those paths add to the cost of the meter and can make ultrasonic flowmeters a costly investment.
Optical flowmeter. Optical flowmeters, using lasers or LED light, detect the perturbations in light beams resulting from turbulence or small particles in the gas stream. Typically, the specific pattern of each set of perturbations is identified by two optical sensors using correlation techniques. By tracking the time-of-flight of the perturbations between sensors placed a known distance apart, the average velocity—and, therefore, the flowrate—of the gas stream can be calculated.
There are two main technologies used in optical flow sensors: laser-two-focus (L2F) (FIG. 11) and scintillation.
L2F optical flowmeter. As a particle passes through each laser beam, it redirects the light away from its normal straight-line path in such a way that an optical sensor (one per beam) detects the scattered light and generates a pulse signal. As that same particle passes through the second beam, the scattered light excites a second optical sensor to generate a corresponding pulse signal. The time delay between two successive pulses is inversely proportional to the velocity of that particle. L2F flowmeters, of course, rely on the continual presence of light-scattering particles within the fluid.
While minimizing installation and maintenance costs, this approach suffers the disadvantage of sensing velocity at only one point within the flow stream. To obtain a measurement of average fluid velocity, the raw velocity measurement provided by the sensor must be corrected based on the expected Reynolds number for the process fluid. Therefore, the flowmeter is equipped with pressure and temperature transmitters in addition to the optical probe (FIG. 12).
Scintillation optical flowmeter. Another technique for optical flow measurement relies on the principle of scintillation, whereby the fluid itself warps the path of light passing through, rather than entrained particulate matter scattering the light.
Scintillation is the same phenomenon responsible for the “twinkling” of stars and city lights viewed from a long distance. As air passes between the light and the observer, pockets of air having different densities (due to differences in temperature) and/or sufficient turbulence cause some of the light to be refracted away from an otherwise straight-line path, making it appear as though the light source is randomly vibrating or oscillating.
Velocity measurements are inferred by a scintillation flowmeter, shown in FIG. 13, much the same as they are by an L2F optical flowmeter: measuring the time difference between two sensors’ detection of the same scintillation pattern.
Scintillation-style optical flowmeters require a long optical path to maximize the angle at which light will be refracted. Therefore, these flowmeters function best when used to measure across the full diameter of a pipe. An interesting feature of this flowmeter technology is that it functions best when the flow regime is highly turbulent, since increased fluid turbulence leads to greater scintillation.
Optical meters do not interact with the flow and are insensitive to changes in gas composition, pressure or temperature. They are also less prone than other meters to loss of signal at very high flowrates. The sensors are located behind glass windows to protect them from the gas flow, but the build-up of residues or dirt on the windows—or fogging in wet gas conditions—may impair the meter’s function. The use of heated windows and/or air-purge systems to remove dirt may remove this drawback.
Optical meters are available as insertion probes for large-diameter lines, with the advantage of easy, weld-free installation. For smaller line sizes (< 6-in. diameter), an available alternative is a meter that can be installed between flanges.
Rangeability is quoted by manufacturers to be 2,000:1 (0.03 m/sec–100 m/sec), though < 0.1 m/sec uncertainty in the measurement increases significantly as the number of detectable perturbations is very much reduced. Above 0.1 m/sec, the quoted accuracy is from 2.5% to 7% of the measured value.
Takeaway. When selecting a flowmeter for flare gas systems, be sure to start by developing a checklist of key criteria that includes performance, the operating environment, and environmental and safety criteria. Look for the lowest installed cost, lowest maintenance and longest life flowmeter technology. Relying on these simple suggestions will help reduce the confusion of multiple choices in flowmeter technologies to arrive at a solution that performs as intended to ensure the plant operates efficiently, safely and with the minimum environmental footprint.
TABLE 1 shows an example comparison of the flowmeters used most for flare gas measurement with a few of the qualitative ratings for easy understanding. HP
LITERATURE CITED
Dipen Tamboli works as Project Manager at The NEWTRON Group, USA. He has more than 21 yr of work experience with companies such as Linde Engineering, L&T Chiyoda, Daniel Measurement and Control, and Deepak Nitrite Ltd. Tamboli has worked across various industries, including upstream and downstream oil and gas, fertilizers and petrochemicals, executing various EPC projects in the FEED, basic and detail engineering phases in both LSTK and cost-reimbursable formats. His global experience includes leading various projects in India, Europe, the U.S., China, Russia and the Middle East.