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GOOD PRACTICE GUIDE

FLARE GAS MEASUREMENT USING ULTRASONIC TRANSIT-TIME FLOW METERS

www.tuvnel.com

Flare Gas Measurement Using Ultrasonic Transit-Time Flow Meters

Contents Foreward 1

1 Introduction 2

2 Standards for Flare Measurement 2

3 Flare Gas Ultrasonic Meters 3

4 Calibration 4

5 Verification 4

6 Data Handling 5

7 Uncertainty 5

7.1 Sources of uncertainty 5

7.2 Basic uncertainty (timing) 6

7.3 Geometry (pipe diameter and transducer 6 dimensions)

7.4 Secondary instrumentation 7

7.5 Flow related sources of uncertainty 7 for ultrasonic flare gas

7.6 Environmental effects 8

7.7 Installation error 8

8 Computational Fluid Dynamics Modelling 9

9 Recommended Further Reading 11

Foreward

The purpose of this good practice guide is to inform the operator of oil and gas facilities of the issues surrounding flare

gas flow measurement using ultrasonic meters and to provide direction on how best to measure and document flare

quantities for emissions monitoring purposes. Topics on where direction is provided include ultrasonic metering, calibration,

verification and the issues associated with the determination of uncertainty. Computational Fluid Dynamics is also included

in the guide because it is a useful technique for determining the installation error that could impact on measurement

uncertainty.

1

1 Introduction

Emergency flare systems are a necessity on any facilities producing, processing, refining, storing or transporting

hydrocarbons. Gas needs to be disposed of quickly during emergencies; such as a fire risk or over-pressurisation of the gas

plant. In some cases, a large quantity of the produced gas is flared because the infrastructure is not in place to export or

reuse it on site. This produces harmful greenhouse gases and other pollutants.

In order to combat this, legislation is in place targeting Carbon Dioxide (CO2) emissions to the atmosphere from these

facilities. The most stringent monitoring and reporting regimes are in the EU, Norway, Canada and, more recently, the USA.

The inclusion of flaring within Phase II of the EU Emissions Trading Scheme (EU ETS) in 2008 means that strict measurement

guidelines are now in place covering the measurement of CO2 emissions from larger combustion facilities.

Many oil and gas facilities will fall into Category B (emitting 50 to 500 kt of CO2 per annum). For these facilities the

minimum uncertainty requirements for reporting flare gas flow rate is given in the accompanying Monitoring and Reporting

Guidelines (MRG) as ±12.5% (95%) on activity data (volume). However, the MRG states that: “The highest tier approach

shall be used by all operators to determine all variables for all source streams for all Category B or C installations. Only if it

is shown to the satisfaction of the competent authority that the highest tier approach is technically unfeasible, or will lead

to unreasonably high costs, may a next tier be used for that variable within a monitoring methodology”. The highest tier

approach dictates 7.5% on volume and, strictly, 2.5% on CO2 emission factor. These are challenging targets for metering

in flare lines.

In the US, mandatory reporting of greenhouse gases (including CO2, Methane (CH4) and Nitrox Oxide (N2O)), both

onshore and offshore, is covered by Final Rule CFR 40 issued by the US Environmental Protection Agency (EPA). In addition

the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) has recently issued Final Rule CFR 30

setting limits on the flaring or venting of natural gas from facilities located in the Gulf of Mexico and Outer Continental

Shelf. These regulations state that all flare and vented gas volumes must be measured to within 5% uncertainty for facilities

producing in excess of 2,000 barrels of oil per day.

2 Standards for Flare Measurement

Some examples of guidance documents for flare gas measurement include HMC 58, published by the Energy Institute in

Aberdeen, UK, and API 14.10, published by the American Petroleum Institute. The UK offshore regulator (DECC) has also

issued guidelines for flare measurement within Module 9 of Guidance Notes for Petroleum Measurement.

Good Practice Guide

2

3 Flare Gas Ultrasonic Meters

Ultrasonic transit time flow meters are the most developed and widely used technology for flare gas measurement, with

many installations offshore and onshore. Relevant standards covering ultrasonic metering for gas flow include ISO TR

12765 and BS 7965, which provides some guidance on the application of ultrasonic meters to flare measurement under

the Class 4 category of meters and a general section on uncertainty.

The main advantages of flare gas ultrasonic meters are a very wide rangeability (> 2,000:1 is reported) and their ability to

determine molecular weight, and hence density of the gas, from speed of sound measurement. A CO2 emission factor can

also be calculated from molecular weight in combination with other parameters and underlying assumptions.

Flare gas ultrasonic meters generally employ a single (or occasionally dual) measurement of velocity along a beam path

orientated at an angle to the flow direction (Figure 1). The plane of the beam is commonly located at the centre of the pipe

(the diametric position), or offset from it by a distance of half the pipe-radius (the mid-radius position). The transducers may

be mounted in-line with bosses angled to the pipe (as shown) or a range of other orientations (such as that shown far right

of inset).

Diametric path Mid-radius path Insertion from top of pipe

Figure 1: Typical flare gas meter arrangement

The velocity range of a flare gas ultrasonic meter is typically quoted as between 0.03 m/s to 80 m/s and above. This is much

wider than traditional gas ultrasonic meters. However, the actual velocity range that can be accurately measured will also

depend on a number of factors including: signal resolution, process conditions and pipe Reynolds number, to name but a few.

Uncertainty for flare gas ultrasonic meters is typically specified by the manufacturers as 2.5% to 5% over a stated range

of velocity, increasing as velocity reduces. However, these figures are only strictly applicable under ideal flowing conditions,

with all critical dimensions accurately measured.


3

Flow

Pressure Temperature

4 Calibration

One major issue for flare gas meters is the lack of a traceable calibration. In many cases the transducers are inserted

through bosses welded to existing pipe and there is no meter spool that can be removed for calibration. Even spool pieced

meters are unlikely to be calibrated (except prior to installation) since the costs involved with shutting the plant down will

tend to be prohibitive. In addition, there is generally a lack of facilities capable of covering the range of flow rates prevalent

in most flare lines.

In situ calibration (e.g. the time-of-flight radioactive gas tracer technique) has the advantage that it can be performed

without the need to remove the flow meter from the line. In theory any uncertainty resulting from installation effect is also

calibrated-out to some degree. The main drawback with in situ calibration is that the flow rate and line conditions are likely

to be unstable during testing.

Controlled gas injection involves deliberately diverting a known portion of gas (e.g. nitrogen or fuel gas) into the flare line

in order to facilitate a comparison between the injected rate and the meter reading. This requires that the flow meters used

to measure injection rate are calibrated and in good condition. This method is at best a functional check unless the process

can be shutdown, and the flare line completely isolated from other gas sources.

5 Verification

Verification of flare gas ultrasonic meters generally involves checking the zero reading at static conditions and comparing

with a previous reading in order to determine if any drift has occurred in the transducers, cabling and electronics. These

tests do not assess the performance under actual flowing conditions and, therefore, do not replace a full flow calibration.

If the insertion bosses have isolation valves and extraction systems. The transducers can then be removed and inserted a

known distance apart in a small calibration chamber filled with a test gas (typically air) at fixed pressure and temperature.

A purpose-built test cell can allow a hydrocarbon gas of known composition to be used instead of air.

In situ field verification may be an option where the transducers cannot be removed from the line. This must be done

during a process shutdown whereby process gas is trapped between two or more isolation valves on either side of the

meter. If the gas can be sampled, this will allow retrospective comparison between measured and calculated speed of

sound. For this method to be effective, any movement of gas due to temperature differentials and/or leakage paths

must be eliminated. In reality, this is unlikely to be fully achieved in a flare line and this method is, at best, a check of

meter functionality.

Zeroing of electronics and cabling - This is carried out with the cables connected to a test chamber with substitute “dummy”

transducers immersed in a test cell. This method does not test whether any drift has occurred in the transducers themselves.

Good Practice Guide

4

6 Data Handling

Flare lines present a unique measurement situation. The flow can be dominated by very low flow for much of the year

interspersed with periods of high flow. Each flare line will be unique. In some instances blow down and high flaring events

will dominate the total gas to flare; i.e. the low flow region will make up the majority of the gas flared.

Flaring can be broadly categorized into three modes of operation: Base load, operational flaring and emergency/blow

down. A sensible way of analyzing the flare data is to determine how much gas is flared under each mode of operation

and then to calculate the impact of the uncertainty in the gas on the total figure over the reporting period.

There will likely be a velocity range over which the data from the flare gas meter can be deemed most reliable. This can

be based on meter resolution, velocity, Reynolds number etc. Outside this region the uncertainty will be higher. Indirect

measurement calculation methods (such as the by-difference technique, whereby the flare gas quantity is calculated as the

difference between the gas produced and that used on the facility or exported) will be needed in cases where the flare

meter fails to give an output or has “saturated” above a maximum flow limit. The low flow region is the most difficult to

deal with in this respect as the uncertainty on the measurements of total gas, fuel, export gas etc. will translate to very

large uncertainty in a much smaller flare value (note: the flare value can even turn out to be negative!).

7 Uncertainty

The basic uncertainty for a flare gas ultrasonic meter for the most part comprises the uncertainty in measured velocity due

to timing resolution and critical transducer dimensions. Any additional uncertainty must be added to this baseline value

to arrive at the total uncertainty figure. The uncertainty in the volumetric flow incorporates the pipe area, flow profile

as well as pressure and temperature (if referred to standard conditions). Uncertainty in density must also be included for

applications where mass flow is reported.

7.1 Sources of uncertainty

Flare gas ultrasonic meters can be affected by a number of factors. The main issues can generally be broken down into the

following categories:

Primary measurement issues:

• Basicmeteruncertainty(calibration/resolution)

• Driftinoutputovertime(electronics,wear,dirtbuild-up)

• Metrological(pipediameter/probealignmentetc.)

• Flowrelated(distortedprofile/swirlaffectingperformance)

• Environmental(ambienttemperature/noise/liquids/dirtbuild-up)

• Dataacquisition(resolution/speedofresponse/damping)


5

7.1 Sources of uncertainty cont.

Secondary instrument issues:

• Instrumentuncertainty(calibration/resolution)

• Driftinoutputovertime(electronics,wear,dirtbuild-up)

• Instrumentlocation(representativemeasurementatmeteredconditions)

• Environmentaleffects(ambienttemperature/noise/liquids/dirtbuild-up)

Process issues:

• Fluidcomposition(componentanalysis)

• Fluidphases(representativesample)

• Calculationofadditionalfluidproperties(e.g.compressibilityandmolecularweight)

It is important to note that these categories may not be mutually exclusive of one another (for example, installation effects

can vary as a function of the process conditions etc.). Many of the above issues will not be taken into account in the

manufacturer’s uncertainty budget, since they will not generally have a detailed knowledge of the installation, operating

conditions, logging procedures etc.

7.2 Basic uncertainty (timing)

The fundamental measurement from flare gas ultrasonic meters is time. Uncertainty increases as the velocity reduces (and

transit time Δt → 0). Timing uncertainty comprises transit-time resolution (i.e. “clock speed” of the transducers), zero error

(time delays in cables, electronics and processing software) and delta time delay (related to the operation of the transducers

alternately in transmit and receive mode).

7.3 Geometry (pipe diameter and transducer dimensions)

The diameter of the flare line is normally determined using wall thickness gauges such as ultrasonic devices. A number of

measurements may need to be taken around the pipe circumference as the pipe may have distorted during welding of

transducers for example.

Given the tight tolerances needed on the transducer dimensions, it is recommended that a specialist metrology survey is

carried out and this would normally be co-ordinated through the meter vendor. Techniques such as Electro-optical Distance

Measurement (EDM) can be used to calculate the critical dimensions of the transducers from external markings on the pipe.

Good Practice Guide

5 6

7.4 Secondary instrumentation

Both pressure and temperature should be measured at the correct location – typically at 2 and 3 pipe diameters

downstream of the meter respectively. Incorrect location of the sensors will result in additional uncertainty in volume flow

rate. Gauges should be ranged to suit the measurement.

➢ Pressure measurement:

o Uncertainty is largely systematic arising from offshore calibration checks

o Drift uncertainty (probably small)

o Absolute pressure gauges are recommended otherwise barometric pressure variations must be taken into account

➢ Temperature measurement:

o Uncertainty is largely systematic arising from offshore calibration checks

o Drift may occur if the sensing probes are subject to deposition or wear

o Response time and probe vibration may be an issue at high flow rates

Note: Uncertainty in Compressibility factor, Z, is likely to be small compared with other uncertainty sources unless liquids,

or a high level of non-hydrocarbon gases, are present.

7.5 Flow-related sources of uncertainty for ultrasonic flare gas

The most severe measurement conditions occur at the extremes of flare loading. At low flow, problems with measurement

resolution, laminar/turbulent transition, stratification and instability can produce unrepeatable results with high

measurement error.

At high flow, signal loss (due to noise, turbulence-related attenuation and beam drift), meter response and the introduction

of liquids in the line (owing to carry-over and/or drop-out) will also increase the uncertainty and may introduce bias to

the measurement.

Signal transmission

Modern meter technologies have the capability to transmit a digital signal which will carry no additional uncertainty beyond

the resolution of the meter electronics. Analogue systems, outputting a voltage, 4-20 mA signal etc., carry additional

uncertainty associated with the resolution of the analogue output. It may be necessary to employ two (or more) analogue

measurement devices to cover the measurement range effectively. In addition, saturation of the signal (e.g. 20 mA limit

reached) may occur during blow downs. In such cases it may be necessary to estimate the flow rate by other means (e.g.

by-difference or inventory calculation).

Reynolds number effects

Flow rates during background flaring can be so low as to be in the laminar/transitional region (typically in the region of

2,000 < Re < 4,000). The shape of the flow profile changes rapidly through this region and is likely to be unstable. If the

flare meter is set up with a profile factor programmed into the meter assuming turbulent flow, this has the potential for

introducing a significant error in the measured flowrate.


7

7.5 Flow-related sources of uncertainty for ultrasonic flare gas cont.

Stratification has been also shown to occur at low Reynolds number whereby thermal gradients exist across the pipe

(induced by strong sunlight or a cold wind blowing across un-lagged flare line). This can affect the flow profile markedly; in

extreme cases the flow may even be re-circulating locally to the transducers causing a negative indication of flow.

Pipe roughness can alter the profile factor at high Reynolds number but this is unlikely to be a major issue for flare gas

lines unless the pipes become unknowingly encrusted with dirt or rust.

7.6 Environmental effects

Changes in composition - Ultrasonic flow meters are relatively insensitive to changes in gas composition, pressure and

temperature provided liquids (or solids) are not present to any degree. However, high concentrations of CO2 can attenuate

ultrasonic energy at the frequencies commonly used for flare applications. Large changes in speed of sound may limit the

resolution of the meter at the lowest flowrates.

Noise - Flow noise must be in the ultrasonic frequency domain to cause a problem for ultrasonic meters. This may be

generated by pressure relief valves during rapid de-pressurization.

Liquids - Liquids tend to cause an over-reading in ultrasonic meters that is dependent on the amount of liquid present, the

flow pattern and line pressure. In addition transducer ports may be periodically flooded causing a loss in signal.

Dirt deposition on transducers: This can change the speed of sound and, hence, transit time measurement. If transducers

cannot be removed for inspection, a check on speed of sound may indicate if serious fouling has occurred.

7.7 Installation error

If the flow profile deviates significantly from the ideal, axi-symmetric profile, the meter will tend consistently misread; this is

referred to as the “installation error”

On oil and gas facilities it is often impossible to meet the upstream and downstream length requirements specified by the

meter manufacturers to ensure that there is no additional uncertainty in the measurement (most commonly stated as

20D upstream and 10D downstream). Note: Longer upstream straight lengths may be needed if the flow is swirling down

the pipe.

Single-path ultrasonic meters are particularly sensitive to installation. Increased turbulence or instabilities generated by some

fittings may also affect the repeatability, especially if the meter is installed very close to the fitting.

The installation error can be removed to some degree using a suitable correction factor. The installation error can be

determined either by bespoke flow testing or by using computer modelling techniques, such as Computational Fluid

Dynamics (CFD). However, the uncertainty in the method of determining the correction factor must be considered in the

overall analysis of the measurement of gas to flare.

Good Practice Guide

8


9

Meter

location

8 Computational Fluid Dynamics Modelling

CFD modelling offers a flexible and cost-effective solution to determining the installation error in the measurement of flare

gas flow meters compared with in situ or laboratory tests.

In order to determine the error, and hence a suitable flow profile correction factor, the flow through the flare gas header

is modelled in 3-dimensional co-ordinates (Figure 2), taking into account the effect of turbulence and wall roughness, as

appropriate. The results of these models are then compared with those determined using a fully developed flow profile

in order to produce a percentage error in measurement. The sensitivity of installation error may need to be assessed at a

number of flow rates (i.e. Reynolds numbers).

Figure 2: CFD modelling of an offshore emergency flare line

Although a very powerful and useful analysis tool, CFD is a numerical method which carries its own uncertainty through

approximations made in the geometry, turbulence models and limitations on the number of computational cells used.

Therefore, an important part of any CFD analysis is validation of the model against representative test data (Figure 3)

so that an uncertainty can be determined for the meter correction factor. This requires a sound understanding of fluid

dynamics and the principles of flow metering.

No. of Pipe Diameters to Path

Figure 3: Comparing CFD with test data for a single, diametric-path flare gas ultrasonic meter

4 m/s (CFD)

30 m/s (CFD)

4 m/s (test)

30 m/s (test)Inst

alla

tio

n e

rro

r (%

)

8 Computational Fluid Dynamics Modelling cont.

The installation error is sensitive to the distance from the installation, the path location, orientation and length. Figure 4

shows the error downstream of an out-of-plane double bend at the two path positions for a range of axial positions and

path orientations. The error can be seen to oscillate and persists for many diameters downstream of the installation.

The errors on a diametric path tend to be negative whilst they are largely positive for the mid-radius path. The degree of

undulation is more extensive at the mid-radius position; of note is that significant error can persist at 100+ diameters from

the bends depending on Reynolds number.

a) Diametric path b) Mid-radius path

Figure 4 – Error from a single-path meter installed at various positions and orientations downstream of a double bend

It would appear from the comparison with test results, and careful examination of the variation in meter error at the various

path positions and orientations, that in most cases a figure of the order of 5% (k=2) may be used for the uncertainty on

the installation error from a single-path ultrasonic meter obtained using CFD modelling.

The current uncertainty levels stated in the Measurement and Reporting Guidelines for the EU Emissions Trading Scheme

are 17.5%, 12.5% and 7.5% (k=2) for tier 1, 2 and 3 respectively (see Appendix A of those guidelines). Taking a baseline

uncertainty for a single-path ultrasonic flare meter of 5% (k=2), and assuming all uncertainties to be uncorrelated, Table 1

shows the maximum uncertainty that can be tolerated on the meter correction factor (as determined in this case by CFD).

This can be as high as 16.8% for Category A facilities.

Note: This example does not take into account additional uncertainty on meter error that may significantly increase the

baseline uncertainty figure.

Good Practice Guide

10

Diameters from bend exit

0 20 40 60 80 10 120

5

0

-5

-10

-15

-20

20

15

10

5

0

-5

04513518090225270315average

0 20 40 60 80 10 120

Diameters from bend exit

Inst

alla

tio

n e

rro

r (%

)

8 Computational Fluid Dynamics Modelling cont.

Table 1 - Maximum tolerable uncertainty in meter correction factor for EU ETS compliance

Category Tier Max EU ETS for

given tier (%)

Meter basic

(%)

Correction factor

(%)

A 1 17.5 5 16.8

B 2 12.5 5 11.5

C 3 7.5 5 5.6

The complex nature of the flow downstream of bends, even under steady and controlled conditions, will make it difficult

to obtain accurate measurements using single-path ultrasonic meters. With this in mind, the use of multi-path ultrasonic

meters is highly recommended for flare gas lines where practicalities and cost constraints will allow.

9 Recommended Further Reading

Hydrocarbon Management Committee 58 - Guidelines for Determination of Flare Quantities from Upstream Oil and Gas

Facilities. Energy Institute, London, May 2008.

API MPMS Chapter 14.10 Manual of Petroleum Measurement Standards, Chapter 14 - Natural Gas Fluids Measurement,

Section 10 - Measurement of Flow to Flares, First Edition.

Guidance Note - Monitoring and Reporting of Flare Emissions under the EU ETS (UK Offshore Oil and Gas) TUV NEL Ltd.,

East Kilbride, Glasgow. http://www.tuvnel.com/

Guidance Note - Ultrasonic Flow Metering for Single Phase Flows. TUV NEL, East Kilbride, Glasgow. http://www.tuvnel.com/

Good Practice Guide - An Introduction to Flow Meter Installation Effects. TUV NEL Ltd., East Kilbride, Glasgow.

http://www.tuvnel.com/

A Practical Approach to Validation and Optimisation of Ultrasonic Flare Flow Meters. TUV NEL Oil and Gas Emissions

Seminar. Aberdeen, 11 June 2008.

Installation Effects on Flare Gas Ultrasonic Meters. Report 2010/261. TUV NEL Ltd., East Kilbride, Glasgow.


For further information, contact:

TUV NEL, East Kilbride, GLASGOW, G75 0QF, UK

Tel: + 44 (0) 1355 220222 Email: [email protected] www.tuvnel.com

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