This article describes and compares ultrasonic and thermal mass technologies used for flare gas measurement and highlights the advantages and disadvantages of each. For ultrasonic measurement, this article refers to Fluenta’s FGM 160 flare gas meter.
An ultrasonic flow meter sends ultrasonic signals across a pipe at a 45° angle to the direction of flow. These signals are captured and used to calculate the transit time (time of flight), and this time is further used to calculate flow. By taking data from temperature and pressure sensors, both volumetric and mass flow can be calculated. Ultrasonic technology offers a very repeatable measurement and is accurate enough to be used for fiscal custody transfer applications.
Mass flow meters maintain a temperature differential between two temperature sensors mounted on a rod. The upper sensor measures the ambient temperature of the gas and heats the gas to maintain the second sensor at 60°F above ambient. Flowing gas molecules transport heat away from the sensor and as a result, the sensor cools. The higher the gas velocity, the more current is required to maintain the temperature differential. This current is used to calculate flow.
- Sensor Design
A meter can be described as intrusive if any part of the meter protrudes into the pipe. Fig. 3 shows a typical general arrangement for a thermal mass flow meter. ‘D’ as indicated in fig. 3 is the insertion depth of the meter.
Flaring is one of the most challenging applications in hydrocarbon metrology. One major challenge encountered is high gas velocities. A process ‘blowdown’ (i.e. an emergency process shutdown where all product is sent to flare) can easily result is gas velocities of more than 120 m/s. In high flow velocities, the knock-out drum will not have enough time to separate the gas and liquids, so all the solids particles will pass through the sensors to the flare. A second, equally important challenge is that these flare lines can be very ‘dirty’, with significant amounts of sand, wax, oil, carbon and other solid objects present in the gas flow.
The combination of these challenges can result in even the sturdiest of intrusive meters becoming damaged. Simple high velocity can bend the sensor, especially when the insertion depth is very long and the gas velocities are very high. If these high velocities are combined with any solid matter, the risk of damage is higher still, with risk to the sensor body from impact damage.
In addition to impact damage, fouling itself can be a problem. If either sensor on a thermal meter should become coated by fouling, then the amount of heat dissipation will change, resulting in significant error. The solution is to remove the probe, clean it and replace it. Unfortunately, many thermal mass meters are not removable under process conditions, so this may require a process shutdown to complete. In many cases, ultrasonic sensors are fitted with a drain plug that allows accumulated liquids to be removed. A high-pressure air jet can be can also be inserted to remove particles from around the transducers.
The transducers in the Fluenta FGM 160 ultrasonic flare gas meter are installed flush to the inner pipe and measure across the whole diameter of the pipe, as seen in figures 4 and 5. Such transducers can be described as ‘wetted but not intrusive’. The advantages to this design are obvious: the transducers are not exposed to flow or potential impact of particles due to high flow velocities, so they are much less likely to be damaged by either.
Ultrasonic meters are generally better at coping with any fouling deposits. A layer of deposits may attenuate the signals but are unlikely to block them completely. Figure 6 shows examples of transducers which were affected by fouling but continued to measure flow at an appropriate level of accuracy.
Accuracy is vital in any hydrocarbon measurement application and is one of the key factors when choosing a meter for flaring. Thermal mass flow meters are calibrated to a single gas composition and assume that this gas composition will be steady and unchanging. Typically, these compositions are provided to the manufacturer at the time of ordering, and adjustments require special software, access to the meter, and some time to execute.
Another challenge in flare gas metrology is that the composition of the gas can change, often significantly and without prior notice. This is especially true for common flare headers where may processes or reactors may lead to a single flare stack. Gas compositions may also drift over time as the quality of the product varies and tweaks to the process take place. Even using expensive solutions such as a process gas analyser may not help, as the latency of measurements means that the flaring event may be over before the result can be supplied to the meter.
The Fluenta FGM 160 calculates the average molecular weight of the gas composition rapidly and with a very high frequency (more than once a second). By combining this with pressure and temperature-derived density information, changes in gas composition can be compensated for as they occur. As such, the FGM 160 can cope with rapid changes in the gas composition without loss in accuracy and without any adjustments or recalibrations.
The API specifically mention the challenge of changing gas compositions in their publication “Manual of Petroleum Measurement Standards. Chapter 14 Natural Gas Fluids Measurement”.
They note that
“The manufacturer should be consulted for the effects of varying gas composition and process pressure over the operating envelope of the meter. For variations in flare gas compositions. the user must provide detailed process stream composition data to the manufacturer for multiple factory calibrations. as required. In such applications. an analyser or other means must be taken to allow the meter to select the appropriate calibration.”
Section 10.4.3.1 of the report goes on to provide modelled examples of changing gas compositions and how they might impact various meters and the measurements they make.
In the three scenarios posited by the API
- The move to a high CO2 composition results in a 2% to 5% error in the volume flow reading of the thermal meter
- The move to a high propane composition results in a 2% to 15% error in the volume flow reading of the thermal meter
- The move to a high hydrogen composition results in a 100% to 300% error (three hundred percent) in the volume flow reading of the thermal meter
- Thermal flow meter errors are expressed as a range due to the composition effect being velocity dependent
- The API note that the volumetric readings from an ultrasonic meter would be unaltered by these changes in composition
3. Turndown Ratio
Turndown ratio (or rangeability) can be defined as the ratio between the maximum and minimum measurable flow. For example, if a meter has a max flow of 10 lpm and a min flow of 1 lpm, the turndown ration would be 10:1.
Turndown is key in flare measurement, as the potential range of gas flows is very high: From the low level associated with just a pilot flame to the very dramatic flows associated with a blowdown situation. A high turndown ratio will provide appropriate sensitivity across the whole range of potential flows and allow the meter to detect leaks to flare of open valves in the system.
Many thermal mass flow meters report very high possible flow ranges but low turndown ratios, for example, a range of 0.1 – 300 m/s with a turndown of 100:1. What this means in practice is a compromise. Users must choose between high range and low sensitivity. If the minimum flow range of 0.1 m/s was chosen, then the maximum flow would be 10 m/s. If this user wanted a maximum flow of 120 m/s, then the minimum flow would be 1.2 m/s, which is not enough to measure pilot flows.
The Fluenta FGM 160 ultrasonic meter has a turndown ratio of 4000:1, allowing measurements as low as 0.03 m/s and as high as 120 m/s without compromise.
4. Piping Requirements
Flow profile is the ‘shape’ which the flow makes in the pipe. It can vary dramatically with pipe layout and is vital for calculating flow. Every meter makes some assumptions about the shape of the flow profile, with ‘fully developed’ or bullet shaped flow profiles being easiest to model. Flows which involve turbulence, swirl and other distortions are more difficult to measure and to model. The more straight pipework available, the more accurate such assumptions tend to be, with straight requirements being expressed in multiples of pipe diameter (e.g. 10D = 10 pipe diameters).
Most meters have a minimum amount of straight pipework required, and this can be a major factor in the selection of a technology. Long straight runs of piping can be difficult to find in many facilities, so lower requirements are advantageous.
As noted above, thermal Mass flow meters intrude into the pipe which can generate some disturbance to the flow profile. To negate these effects meters typically require 20D upstream and 10D downstream.
A Fluenta ultrasonic flow meter under the same conditions would require just 10D upstream and 5D downstream (see figure 7). In addition to the added convenience, pipework requirements can save significant money. Based on a 36” flare header, a plant operator could require 45’ (13.7 meters) less piping. We have tested many possible pipe orientations and options to understand the needs of our clients and advise accordingly to ensure our technology will work effectively.
5. Point Measurement Vs. Cross Pipe Measurement
A thermal mass flow meter is installed on the pipeline by ensuring the sensor tip is positioned in the centre of the pipe, where the point of maximum flow is normally expected. The sensor measures the gas flow at this point, assumes a ‘perfect’ flow profile across the rest of the pipe diameter, and reports a result accordingly. This technique is known as a point measurement and is shown below in figure 8.
By contrast; the Fluenta ultrasonic meter sends ultrasound from one pipe wall to the other, allowing the full flow profile to be measured across that line (or chord) of the pipe. Whilst the system must still make assumptions about the flow profile, it does so on the basis of much more data, and therefore the assumptions are likely to be more valid. Fiscal metering uses many paths (8 is typical) to provide intricate detail about the flow profile, and very high levels of accuracy.
Whilst flow profiles which are close to ‘perfect’ can be created in a lab environment, flow profiles in the real world are often complex. Effects such as density separation and complex pipework with elbows and valves, and swirl all create difficult flow profiles. With thermal mass meters measuring such a small part of the flow path, some flow profiles can confuse the meter resulting in significant inaccuracy.
By contrast, ultrasonic meters cope well with moderately disturbed flow profiles, and the accuracy and repeatability are maintained.
Maximum Pipe Size: Thermal mass flowmeters must reach the centre of the pipe, so there is a mechanical limit for the size of the meter. Most can be supplied up to a maximum pipe size of 72”. For ultrasonic flowmeters, there are no mechanical limits. Fluenta has provided meters on pipes greater than 100” in diameter.
Data Output: Thermal mass flow meters provide flow rate just in terms of mass flow. Ultrasonic flow meters can provide the mass flow or volumetric flow. In addition, ultrasonic flow meters can give an average molecular weight of the gas as well as density at standard and operational conditions. Ultrasonic meters can also provide simple readings of temperature and pressure.
Power Consumption: As the sensors in a thermal mass meter need to be heated to maintain the temperature difference between the reference sensor, a thermal mass flow meter will consume more power compared to ultrasonic flow meter. The Fluenta FGM 160 meter has a power consumption of around 13W, whilst for thermal mass flow meter the power consumption will vary with flow.
Tests by many of the world’s largest oil and gas companies, as well as key institutes regularly find that ultrasonic meters are the most appropriate technology to use for flare gas metering applications.
The Fluenta FGM 160 flare gas meter is both accurate and flexible and provides a solution to almost every flaring challenge the hydrocarbon industry can provide.
With more than 30 years’ experience in sensing technology, Fluenta is trusted by major companies in the chemical and Oil & Gas Industry and present in 75% of offshore installations. With 1,500 deployments and in excess of 400 customers worldwide, Fluenta is your trusted partner for flare gas measurement, delivering accurate information for better decisions.
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