Ultrasonic Gas Flow Meters

What Is a Multipath Ultrasonic Gas Flow Meter?

Every cubic meter of gas that changes hands between a pipeline operator and a gas buyer ends up on an invoice. Meters on transmission lines, at city gate stations and at storage facilities are therefore expected to deliver not only low uncertainty but also measurement that stays stable for years and can report on its own health. A multipath ultrasonic gas flow meter is a metering system built for this purpose: a full-bore meter body, pairs of transducers mounted in the body, and signal-processing electronics.

The meter determines the gas velocity across the pipe section over several acoustic paths and converts it into actual volumetric flow at operating conditions. When pressure, temperature and gas composition are fed to the electronics, flow corrected to standard conditions, mass flow and energy flow can also be calculated within the meter itself — allowing it to serve as a parallel, backup calculation layer alongside a flow computer.

The instruments on this page are intended for gas measurement only: natural gas, hydrocarbon gases and industrial gases. The more paths a meter has, the finer the resolution with which it samples the velocity profile; the eight-path arrangement is designed to identify and compensate, while measuring, for the asymmetric profiles and swirl created by real-world features such as elbows, valves and short straight runs.

The Transit-Time Principle and 8-Path Chordal Measurement

In the transit-time method, the measured quantity is the time a sound pulse takes to travel through the gas from one transducer to the one opposite. When gas is flowing, sound travels faster with the flow and slower against it. The meter evaluates this difference on eight separate paths at once:

1.      Generating acoustic pulses: Each measuring path consists of a transducer pair mounted on opposite sides of the meter body. In total, 16 transducers operating at 125 kHz take turns sending and receiving acoustic pulses with and against the flow; a single transmitter controls pulse generation and timing.

2.      Measuring the transit-time difference: A pulse traveling with the flow arrives sooner, and one traveling against it arrives later. The difference between the two times is proportional to the mean gas velocity along that path, while evaluating both times together yields the speed of sound in the gas.

3.      Combining eight paths into one measurement: The transmitter combines the velocities from the eight chordal paths to calculate the mean gas velocity across the pipe section. Multiplying the mean velocity by the internal cross-sectional area gives the actual volumetric flow at operating conditions.

4.      Conversion to standard conditions: A pressure transmitter connected to the pressure tap on the meter body and a temperature measurement in the line feed the electronics through isolated 4–20 mA inputs. Together with the gas composition, these data are used to calculate corrected volume, mass and energy flow.

5.      Continuous self-monitoring: Signal quality, speed of sound and velocity profile are monitored continuously on every path. Consistency between the paths produces diagnostic information on both transducer health and flow conditions.

Crossed Paths in Four Planes and Swirl Compensation

The eight paths are arranged in four positions and in opposing directions. This crossed layout lets the effects of asymmetric velocity profiles offset one another between paths and allows swirl in the pipe to be calculated more precisely. As a result, flow disturbances from elbows, short straight runs or compact station designs have less effect on the measurement; installation-related deviation is reduced, as is the need for long inlet runs or flow conditioners.

Confidence Through Speed-of-Sound Comparison

The meter can compare the speed of sound it measures with a theoretical value in real time. The theoretical value is derived with the AGA 10 (2003) or GERG-2008 (AGA 8, Part 2, 2017) method, taking pressure, temperature and gas composition as inputs. Composition data can be read from a gas chromatograph over Modbus. A deviation between the two values is an early indication that something may be wrong with a transducer, the composition data or the pressure and temperature measurements.

Bidirectional Measurement and Pressure Loss

The transit-time method works regardless of flow direction: the meter measures in both directions and keeps separate forward and reverse totals. This makes single-meter measurement possible at sites such as underground storage facilities, where gas is injected or withdrawn depending on the season. Because the full-bore body does not narrow the flow to measure it, the meter causes no additional pressure loss — an important factor for compressor and operating costs.

Velocity measurement yields actual volume at operating conditions; the standard volume and energy values used for custody transfer depend directly on the quality of the pressure, temperature and composition data. The meter should therefore be treated as a system together with the auxiliary measurements at the metering station.

Key Technical Capabilities

·         8-path, 16-transducer chordal design: Eight paths set in opposing directions across four planes sample the velocity profile at high resolution; a single transmitter combines the data from all paths.

·         High accuracy with calibration: On flow-calibrated meters, accuracy is ±0.1% of reading and repeatability ±0.05% of reading between 1.5 and 30.5 m/s. Performance meets the requirements of AGA 9 (2017, 3rd edition) and ISO 17089.

·         Non-wetted, metal-encapsulated transducers: The titanium-encapsulated transducers have no direct contact with the process gas, aiming at a long service life in gases carrying oil, wet gas or corrosive components. They are standard up to DN900 and optional at DN1050.

·         Transducer replacement under pressure: The one-piece transducer capsule can be withdrawn without depressurizing the line and without a high-pressure extraction tool; the non-wetted design prevents gas release during this work.

·         Mechanical signal amplification: A mechanical amplifier array in the transducer strengthens the acoustic signal and limits attenuation and reverberation effects.

·         Built-in corrected volume, mass and energy calculation: Standard-condition flow rates are calculated from pressure, temperature and composition data; since the archive logs also contain these values, the meter can act as a backup flow calculator.

·         In-situ meter verification and predictive diagnostics: A verification function that summarizes meter and process condition in a single result generates PDF/XML reports on a monthly schedule or on demand; predictive diagnostics support a fast response to abnormal conditions.

·         Comprehensive alarm set: Separate alarms for buildup on the pipe wall, blockage, abnormal velocity profile, presence of liquid and reverse flow; latching alarms and alarm prioritization are supported.

·         Auditable data logging: Hourly logs are kept for 180 days and daily logs for five years. The audit log records the name of the user making each change, and a hardware write-protect switch locks the configuration.

·         Extensive I/O and communication: Six frequency/digital outputs, one analog output, two isolated analog inputs for pressure and temperature, Modbus RTU/ASCII over RS-232/RS-485 and Modbus TCP over Ethernet; an optional expansion module adds a further serial port and a three-port Ethernet switch.

·         Optional local display: A three-line local display can scroll through up to 10 values chosen from 26 variables, at an interval adjustable from 1 to 100 seconds.

Technical Specifications

The values below are typical data for the 8-path ultrasonic gas flow meter. Values that vary with transducer type, line size, pressure class and body material should be confirmed at project stage for the selected configuration.

Body and flange pressure classes are given for −29 … +38 °C (e.g., 51.1 bar for the PN 50 class with a carbon steel body); the allowable pressure may be lower at higher temperatures. Capacity tables are based on a Schedule 40 bore, 15 °C and a typical natural gas composition and are intended for preliminary sizing only.

Key Advantages

·         More compact metering station: Because metrological performance can be targeted with 5D of straight pipe and no flow conditioner, station length, weight and capital cost go down, and layout becomes easier at space-constrained offshore and urban stations.

·         Zero additional pressure loss: The full-bore body and a design that needs no flow conditioner reduce compression costs and eliminate the maintenance caused by clogging that can occur with flow conditioners.

·         Low sensitivity to installation effects: The crossed eight-path layout compensates for asymmetric profiles and swirl caused by elbows and valves, helping the field measurement stay close to the laboratory calibration.

·         Uninterrupted maintenance: Being able to replace transducers under pressure without special tools reduces the need to depressurize the line, vent gas or schedule an unplanned shutdown.

·         Bidirectional measurement with one meter: For two-way flows such as injection into and withdrawal from storage, forward and reverse totals can be kept without building a separate meter run.

·         A measurement that reports its own health: Per-path speed-of-sound, profile and signal diagnostics, together with buildup, blockage and liquid-detection alarms, make it easier to spot changes in measurement quality before they reach the invoice.

·         Calculation redundancy: Corrected volume and energy values calculated inside the meter can serve as an independent reference for cross-checking flow computer results.

·         Wide capacity range: Sizes from DN250 to DN1050 and a velocity range of 0.5–30 m/s make it possible to build high-capacity stations with fewer parallel meter runs.

Applications Along the Natural Gas Chain

The 8-path ultrasonic gas flow meter is used at points where natural gas changes hands on its way from production to the end user, or where large volumes are monitored. Typical locations include:

Custody Transfer on Transmission Pipelines

The main measuring instrument at high-volume delivery and receipt points on natural gas transmission pipelines. High accuracy, long-term stability and metrology approvals are basic requirements for measurement that forms the basis of billing.

City Gate Stations

Used at delivery and receipt points at the transition from the transmission network to the distribution network. The compact piping layout makes it easier to fit the meter into the limited space of urban stations.

Underground Gas Storage Facilities

At storage inlets and outlets, flows that reverse direction between injection and withdrawal periods can be monitored with a single meter thanks to bidirectional measurement.

Gas Processing Plants

Used to monitor raw and processed gas quantities at plant inlets and outlets. The non-wetted transducer design is intended to protect transducer life in gases that may carry oil or liquid.

Power Plant Gas Inlets

Used on the inlet lines of gas-fired power plants to monitor fuel consumption and energy content; energy flow can be calculated using composition data.

Onshore and Offshore Gas Production

Used for sales gas and inter-facility transfer measurement at onshore and offshore production sites; the compact station design suits the space and weight limits of platforms.

Ultrasonic Gas Flow Meter Selection and Installation Requirements

Selecting an ultrasonic gas meter covers the piping layout and auxiliary measurements of the metering station as much as the meter itself. The headings below are the key inputs to a technical assessment:

Gas and Process Conditions

·         Gas composition and the source of composition data (fixed value or online gas chromatograph)

·         Minimum, normal and maximum flow; volume at standard and operating conditions

·         Operating pressure range; whether there is low-pressure operation below 6.89 bar

·         Gas temperature and minimum design temperature

·         Likelihood of oil, wet gas, liquid carryover or corrosive components (e.g., H₂S)

Capacity and Velocity Limits

·         qmin, qt and qmax transition velocities for the selected line size

·         Low-pressure velocity limits: for DN400–DN500 meters, 15.2 m/s at 345 kPag and 30.5 m/s at 689 kPag and above; lower limits apply from DN600 upward

·         For DN300 and smaller meters, isolated transducer mounts and a suitable transducer type are required for 0–689 kPag operation

·         Pipe schedule and the resulting internal diameter

·         Unidirectional or bidirectional flow requirement

Piping Layout and Flow Conditioning

·         At least 5D of straight pipe at the meter inlet for installation without a flow conditioner

·         Optional installation layout with a flow conditioner; other pipe lengths can be adapted per project

·         For bidirectional meters, both sides treated as inlets and flow conditioning used for optimum results

·         An additional 3D of pipe length for extra connections such as a sample probe or test well

·         Recommended location of the temperature measuring point and the pressure connection on the meter body (½ in NPT or pipette type)

Materials and Pressure Class

·         ANSI/PN pressure class and flange face type (RF, RTJ, compact flange, hub)

·         Body material and whether impact-tested carbon steel is required

·         NACE-compliant design, NORSOK or PED requirements

·         Transducer O-ring material (NBR or FKM) and coating/paint requirements

Electronics, Integration and Approvals

·         Frequency, Modbus RTU/ASCII or Modbus TCP connection to the flow computer and SCADA

·         Need to read composition from a gas chromatograph via Modbus serial or TCP

·         Hazardous-area approval: ATEX/IECEx, UL/cUL, INMETRO or EAC

·         Metrology approval: OIML, MID or country-specific type approvals

·         Cable entry type (¾ in NPT or M20) and need for a local display

For smaller line sizes or different custody transfer approaches, differential-pressure solutions such as orifice metering systems can also be considered; the technology should be chosen by weighing flow range, pressure, station footprint and legal metrology requirements together.

Metrology, Safety and Design Standards

The metrology, hazardous-area and mechanical design standards defined for the meter are summarized below. Some approvals are selected as part of the order configuration.

The approval list refers to the meter itself and is for information; the legal metrology requirements applicable to the metering station as a whole, and natural gas metering regulations in Türkiye, should be evaluated for each project together with the TLY Enerji engineering team.

The TLY Enerji Approach to Gas Metering Engineering

Uncertainty at a custody transfer point does not come from the meter alone; piping layout, flow conditioning, pressure and temperature measurement, gas composition and the calculation chain all shape the result. That is why TLY Enerji treats the ultrasonic gas flow meter as part of the complete metering station: we check meter size and velocity limits against your flow and pressure profile, and assess straight-run and flow conditioner needs together with the station layout.

During the project we provide engineering support for planning the auxiliary measurements and the gas chromatograph connection, flow computer and SCADA integration, project documentation and commissioning. In operation, we work with your site teams to interpret diagnostic trends and verification reports, helping to detect changes in measurement quality early.

·         Flow profile analysis and meter sizing

·         Piping layout and flow conditioning assessment

·         Integration of pressure, temperature and composition measurements

·         Flow computer and SCADA communication design

·         Commissioning and diagnostic data interpretation support

Frequently Asked Questions

How does an ultrasonic gas flow meter work?

Transducer pairs mounted opposite each other on the meter body take turns sending acoustic pulses with and against the flow. The pulse traveling with the flow arrives sooner. The difference between the two transit times is proportional to the mean gas velocity along that path. The velocities from the eight paths are combined into the mean velocity across the pipe section, and multiplying it by the cross-sectional area gives actual volumetric flow.

What does the 8-path design add to the measurement?

Because the eight paths are arranged in four positions and opposing directions, the velocity profile is sampled at higher resolution. This layout balances asymmetric profile effects between paths and allows swirl to be calculated more precisely. The influence of disturbances from elbows, valves or short straight runs is therefore reduced, and OIML Class 0.5 performance can be targeted with 5D of straight pipe and no flow conditioner.

How much straight pipe does an ultrasonic gas flow meter need?

In the recommended layout without a flow conditioner, at least 5D of straight pipe at the meter inlet is sufficient. A layout with a flow conditioner can also be used if preferred. For bidirectional meters, both sides are treated as inlets and flow conditioning is recommended for optimum results. An additional 3D of pipe may be needed for extra connections such as a sample probe or test well. The final layout should be based on the station arrangement.

Which standards and approvals apply to custody transfer?

The meter meets the performance requirements of AGA 9 (2017, 3rd edition) and ISO 17089. On the metrology side it holds OIML R 137 Class 0.5 and MID 2014/32/EU (MI-002) Class 1.0 approvals, with country-specific type approval options for China, Brazil and the EAC region. For custody transfer applications in Türkiye, the regulations and approval requirements for the metering station as a whole must be evaluated separately.

Can an ultrasonic gas flow meter be used to measure liquids?

No. The meter described on this page is designed to measure natural gas, hydrocarbon gases and industrial gases; it has no defined performance for liquid measurement. Its liquid-detection alarm exists to warn the operator about unwanted liquid in a gas line. For flow measurement on liquid lines, other technologies suited to the fluid and the process should be considered.

Can the transducers be replaced while the line is under pressure?

Yes. With the titanium-encapsulated, non-wetted transducers, the one-piece capsule can be withdrawn without depressurizing the line and without a high-pressure extraction tool. As the transducer has no contact with the process gas, no gas is released during this work. Meters fitted with older transducer types can be upgraded to this transducer type. The maintenance procedure should be planned in line with the site's occupational safety rules.

How is meter capacity calculated?

For preliminary sizing, the standard capacity at maximum velocity for the relevant line size and operating pressure is scaled by the desired velocity divided by the maximum velocity. For example, if a DN250 meter at 4,500 kPag has a capacity of about 280 thousand Sm³/h at 30.5 m/s, its capacity at 21 m/s is about 192.7 thousand Sm³/h. These values are based on a typical gas composition and a 15 °C reference; exact sizing must be done before ordering.

Can an ultrasonic gas flow meter calculate energy flow?

Yes. Using its pressure and temperature inputs and gas composition data, the meter electronics can calculate corrected volume, mass and energy flow. Composition data can be read from a process gas chromatograph over a Modbus serial or TCP connection. In custody transfer calculations these values are generally used as a backup to, and cross-check of, the flow computer results.

Which diagnostic functions are available?

Transducer health, signal waveforms, velocity profile and speed-of-sound comparison can be monitored per path. Alarms cover buildup on the pipe wall, blockage, abnormal profile, liquid detection and reverse flow. The in-situ meter verification function summarizes meter and process condition in a single result and generates PDF/XML reports on a monthly schedule or on demand. Hourly logs are kept for 180 days and daily logs for five years.