Ultrasonic flare gas meters have become the go-to technology for accurate flare gas measurement in the oil and gas industry – from upstream through to downstream.
Ultrasonic meters allow operators to reliably meet stringent regulations and uphold corporate responsibility policies to improve the environmental landscape. However, despite their known resistance to extreme process conditions and fouling, the ultrasonic measurement sensors must be verified at least once per year to ensure that they remain within regulatory specifications.
This article explores some of the regular validation options.
Emissions from flare gas have been attracting attention from legislators worldwide, and the trend of ever-tightening regulations is expected to continue.
The growing number of environmentally-conscious stakeholders and the roll-out of initiatives to meet net-zero goals mean that operators cannot afford to neglect their green credentials – otherwise, they risk compromising their social licence to operate and will rack up increasingly prohibitive financial penalties.
What can be measured can be changed, and opting for ultrasonic flare measurement is the first step in controlling emissions from flare gas. However, verifying the meter is a prerequisite to maintaining regulatory compliance and avoiding fiscal or reputational reprimands.
Why use ultrasonic flowmeters for flare gas measurement?
Measuring flare gas is arguably the most difficult form of gas flow measurement. The process conditions upstream, midstream and downstream are wildly unique and extreme, requiring a robust solution that helps plant operators to collect vital data to ensure safety and legal compliance.
Flare gas is subject to massively-fluctuating velocity ranges, varying atmospheric conditions, extreme temperatures, and mixed compositions, which makes it especially difficult to accurately measure its flow. The measurement challenge is increased further in very large pipe sizes and when installations lack straight run pipelines or have insufficient flow conditioning, such as on offshore platforms.
When choosing a measurement solution, operators must consider technical suitability and reliability to handle their unique process conditions – something ultrasonic meters have been proven to be the best at.
Ultrasonic meters are less impacted by fouling and do not require plant shutdown for maintenance purposes, setting them aside from other technologies. Ultrasound is also the most accurate and repeatable form of measurement to ensure legal compliance, save costs, and close gaps in mass balance.
Additionally, chapter 14, section 10 of the American Petroleum Institute (API)’s Manual of Petroleum Measurement Standards – commonly referred to as API 14.10 – scientifically outlines the advantages of ultrasonic flare meters compared to other technologies.
Ultrasonic principle of operation
There are various types of ultrasonic flare meters and system set-ups, such as Bias-90 insertion and cross-pipe in a single or dual-path arrangement.
A typical configuration of a Fluenta flare measurement solution, for example, uses two ultrasonic transducers placed at an angle flush to the inner diameter of the pipe (pipe ID), either by hot tapping or as an inline meter (installed when already welded onto a spool pipe). Both transducers send and receive ultrasonic signals – one with the flow of gas and the other against it.
The meter can determine the flared gas velocity and the volumetric flow, among many other attributes, by calculating the difference in travel time an ultrasound pulse takes when moving from transducer 1 and transducer 2 and back (t21 – t12). This is known as the ‘time of flight’ method of measurement (see Figure 1).
Over time, as components in the system age, the continuous ultrasonic wave offsets input at the point of production and commissioning can shift, causing an increase in system uncertainty. As well as this, the transducers can become coated by fouling which could attenuate their signals and reduce their levels of measurement accuracy. These factors can be managed by regular meter verification via calibration.
The need for flare gas meter verification
Maintenance is an essential step in preserving equipment, especially when it is exposed to harsh environmental conditions. Aside from satisfying legal requirements to carry out annual or periodic checks, flare gas systems unchecked could present reduced accuracy and provoke unplanned repairs and installation shutdowns, increasing safety risks.
An unplanned shutdown can be a costly byproduct of poor calibration. Unscheduled repairs can last several weeks and rack up millions in lost revenue. Additionally, poorly-operating flare measurement systems can compromise the safe disposal of excess gas and increase the potential for safety hazards, triggering an explosion.
ISO 17089-2, BSI’s BS 7965, and IECEx standards provide guidance for the operation and verification of ultrasonic flow meters. They highlight the need for regular checks to ensure safety and define the required measurement accuracy which must be maintained.
Aside from ensuring safety and regulatory compliance, accurate flare measurement supported by regular meter verification helps operators to maintain mass balance by identifying leaks, reducing losses in process gas, and establishing overall reliability.
Types of flare meter verification
There are three-meter verification options: multi-point, zero-point, and in-situ verification. These options differ in their levels of thoroughness and feasibility and apply to different scenarios.
Multi-point calibration
Multi-point calibration uses a flow rig to compare meter readings against an extremely accurate master meter. This master meter provides the standard, and a flare measurement system is calibrated against this at multiple points of flow to ensure that the required accuracy is met across the range of measurement.
Zero-point calibration
Zero-point calibration of flare gas meters occurs during installation, as well as at regular intervals during the meter’s lifetime. It is a crucial exercise to ensure consistent reliability of measurement.
To calibrate an instrument, measurements need to be compared to a standard value to determine accuracy. There are four key factors required to perform a zero-point calibration. These are:
- Zero airflow
- An accurate tip-to-tip distance
- Known Velocity of Sound of the gas (VoS)
- Known pressure and temperature readings
Consider the Fluenta FGM 160, which accurately tracks gases emitted through a flare stack, detects leaks for mass balance, and accurately measures very low and high flow rates in flare systems.
Zero-point calibration of this meter – and the setting of span values – reveals an allowed measurement range for the instrument. With this information, technicians can easily identify when the flare meter is malfunctioning or performing below its required levels.
Instead of being calibrated at multiple points, the system is evaluated in a no-flow environment to establish a zero-point reading. If the meter has strayed from this point, then it may produce incorrect readings, i.e. showing flow when there is none.
In-situ verification
This form of meter verification occurs whilst the transducers remain in the pipeline. However, it is not as thorough as a zero-point calibration due to reasons relating to the four key factors previously outlined.
The difference between the meter verification options
Zero-point calibration
A zero-point calibration can be performed to verify the reading of an installed ultrasonic flare meter in the field. The flare meter manufacturers generally provide documentation for functionality testing, verification and inspection intervals, as well as uncertainties and speed of sound calculations.
In the case of a zero-point calibration of a Fluenta system, a certified service engineer, or the operator, removes the transducers from the pipe and puts them in a ‘zero box’ or Fluenta’s FlareCalTM calibration box. This box provides a sealed environment, ensuring that there is no airflow.
The engineer uses this alongside the tip-to-tip distance, VoS, and pressure and temperature readings. This process rigorously verifies that the transducers are working correctly. If, for some reason, they read as anything other than ‘0’, the engineer will input an offset to correct the error.
As well as calibration, the process also allows for an important visual inspection. Occasionally, a meter may read incorrectly due to a build-up of debris or fouling on the sensors. This is especially true if the sensors intrude into the pipe, as this leaves them particularly vulnerable to fouling. This will impact measurement, but it is challenging to diagnose without removing the sensors from the system.
This in-field verification offers the opportunity to perform the following checks:
- Inspect installed meter specifications and operating conditions against specification sheets and drawings
- Check pressure and temperature transmitters
- Check wiring for any signs of moisture or physical damage
It is worth noting that some forms of flare meter verification can be operator-managed, and others need to be managed by an external manufacturer-certified engineer. In the case of Fluenta’s flare solution, both options are available depending on operator needs, using their self-managed Fluenta FlareCal calibration box.
In-situ verification
This form of meter verification is not as thorough, as it does not allow for the important visual inspection of the ultrasonic sensors.
When performing this check, it is worth keeping in mind the impact of the zero calibration factors mentioned previously:
- Zero airflow: transducers are incredibly sensitive, and even wind blowing over the top of the flare stack can impact calibration. Without removing the transducers and inserting them into a zero-box, or a calibration device, in which there is no flow at all, it is difficult to understand whether they are truly reading correctly. This is especially important when looking for accurate measurement at low flow rates.
- The velocity of sound: if the transducers remain in the pipe, then it won’t be just air passing through. To thoroughly calibrate a system, an accurate gas composition is required at the time of measurement. This can be obtained but requires the installation of extra equipment, such as a gas chromatograph. However, this only takes a snapshot and not a live reading. If the gas composition changes during calibration, the result will be invalid.
It should also be noted that during an in-situ verification, the transducers are not visually inspected as they remain in the pipe, and debris in the process may adversely affect the results.
Online health check and performance monitoring
Some ultrasonic flowmeters provide the ability to run remote online diagnostics for performance checks. These diagnostics can be used as a form of in-situ meter verification as they allow operators to assess the performance and the accuracy of the flare meter without the need to remove and physically inspect or calibrate the meter. However, in-situ verification has limitations for thorough system validation and should not be the only form of verification relied on for the required regulatory annual checks.
Flare gas measurement manufacturers can provide operators with detailed diagnostic parameters, along with acceptable limits. They include parameters to verify transducer and electronics functionality checks, flow profile, signal strength, meter performance and more.
Fluenta’s flare measurement solutions come with the UFM Manager software, which enables operators to perform a remote health check. The health check should be used as the first step in diagnosing any issue should there be a reason to believe that the meter is reading incorrectly. For a more in-depth verification process, a zero-point calibration should be performed.
Conclusion
Legislators and manufacturers both state the need for annual meter verification to meet environmental and air quality regulations and to ensure that flare measurement solutions remain safe, accurate, and reliable. Ensuring that the flare meters remain in good condition also helps to close the gap in mass balance, detect leaks, save costs, and reduce emissions.
It is becoming easier to achieve all of the above, as operators have access to several forms of meter verification, albeit each with its individual advantages and drawbacks.
