Improving flowmeter calibration accuracy

Liquid-measuring devices are used in a huge variety of commercial applications. There is currently a debate within the flow measurement community regarding the merits of using real fluids for the development, testing and calibration of multiphase flow meters. However, a consideration of thermophysical properties of fluids and basic metrological principles indicates that the use of stable, well-characterised substitute fluids, can offer a better solution.

Proponents of the use of live fluids such as natural gas, crude oil and brine, argue that flow loops using such fluids are more representative of the conditions that meters will encounter in service. However, the measurement of multiphase flow in oil & gas poses particular difficulties when calibrating and testing flowmeters as it has many variables that require complex measurements. For example, the nature of live fluids mean that their properties and the dependence of these properties on temperature and pressure may be different each time they are used. 

This means that there is less confidence in the properties of these fluids, ultimately resulting in higher uncertainty in the reference flow rate for a device under test. Conversely, reference fluids are stable and predictable, thereby delivering consistent and reliable measurements, resulting in lower uncertainty in the reference measurements before the flowmeter goes into the field. Once in the field, overall measurement uncertainties can be derived using PVT data along with fluid sampling and physical properties modelling, as well as testing against test separator systems.  

Multiphase flow loops typically consist of a three-phase separator, reference flow meters for each of the three phases, a test section and various pumps and other equipment for circulation of the fluids.

Each liquid phase of a typical multiphase loop operating with reference fluids will be metered through its own reference flow meter and fresh nitrogen is added and metered through its own flow meter. On-line density measurement of the liquid phases, combined with off-line measurements of the pure liquids, enables the mass flow rates of the liquid phases to be determined and hence the volumetric flow rates at the device under test.  

The temperature and pressure of the gas phase at its reference meter are also measured, allowing the mass flow rate to be calculated. The volumetric flow rate of the gas at the device under test can then be calculated from its local temperature and pressure at that point. 

This does make the assumption that all the gas (nitrogen in this example) remains in the gas phase and does not absorb any of the oil or water. To test this assumption, NEL has undertaken a series of calculations, which confirms that the nitrogen remains in the gas phase and doesn’t absorb liquids.

Now consider a multiphase facility using real fluids. It can no longer be assumed that there is no partitioning between the phases as the operating conditions (temperature and pressure) change from the reference meters to the device under test. 

To test this assumption and determine the extent of this partitioning, a similar set of calculations was performed with fluids representative of a live crude and natural gas. In this case, the density difference was 7% due to partitioning of the hydrocarbon components between the vapour and liquid phases. Additional calculations were undertaken for a high-pressure multiphase flow loop using live fluids and similar differences were found in the calculated densities of the gas phase. Unless this partitioning is taken into account the density difference calculated translates directly to an error in the calibration.

The calculations undertaken above are only possible with knowledge about the fluid compositions. While it may be possible to determine the gas phase composition in real time by gas chromatography, the liquid phase composition can generally only be determined by sampling and off-line analysis. Even if this approach is used, there still remains inherent uncertainties that arise from the equations of state – all equations of state require additional parameters (binary interaction parameters) to account for non-ideal behaviour of real mixtures. These uncertainties can be of the order of several percent, potentially of the same order as the required measurement uncertainty for the device under test.  

The effects of temperature and pressure on fluid properties must also be accounted for. For a single-phase facility this can most easily be achieved by using a pure fluid, for example, water, or a fluid of known, and stable, composition. For a facility testing meters under multiphase conditions, this approach will also yield the lowest uncertainties in fluid properties, since the effects of temperature and pressure on the reference fluids will be low. 

However, this will not be the case if real fluids are used, since they are, by their nature, much less stable with time, and the temperature and pressure dependence of their fluid properties will be less well known. In addition, differences in temperature and pressure between the reference device and the device under test will cause changes in partitioning of components between the gas and liquid phases, leading to increased uncertainties in the fluid properties.

As research shows, the use of ‘real’ fluids such as natural gas, crude oil and brine, increases uncertainty on the calculated fluid phase properties. This is due to the issues of dealing with essentially unknown partitioning of hydrocarbon components between the vapour and liquid phases. 

In order to achieve the lowest overall uncertainty, it is necessary to control all of the parameters as accurately as possible. This would, therefore, justify that the best metrological approach is to eliminate this issue by the use of suitable stable, well-characterised reference fluids. For this reason NEL has recently switched from using crude oil to refined oil as part of it multiphase flow loop meter testing. 

This is consistent with the approach recommended in the current issue of Department of Energy and Climate Change’s Guidance Notes for Petroleum Measurement, Issue 9, 

July 2014. (Section 9.7), which makes specific mention of the need to account for possible transfer of components between phases and a preference for ‘model’ fluids, to minimise additional uncertainties.

NEL is a provider of technical consultancy, research, measurement, testing and flow measurement services to the energy and oil & gas industries, as well as government and offers a centre of excellence for flow measurement and fluid flow systems.