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Dr Norman Glen gives a detailed look at multiphase flow metering in the oil and gas industry.
The first attempts at developing a multiphase flow meter were undertaken in the late 1980s and included an early design developed by NEL. Research and development continued into the early 1990s with the first prototype meters emerging. The next phase of development through the mid 1990s was a continual process of iterative development as problems were encountered with prototype models and awareness developed of the issues, capabilities and weaknesses of the different types of technologies. Much of this development was pushed along by the experiences and test results coming out of several large joint industry test programmes.
The first true commercial multiphase meters emerged on the market later that decade from a number of manufacturers. Most developments were initially focused on topside models, with several manufacturers going on to develop subsea versions of the meters. In most cases the meters were then subjected to lengthy field trials to evaluate performance, reliability and ease of operation.
The market has matured significantly in the last decade with significant numbers of meters now installed. This has occurred in parallel with the growing acceptance from operators and regulators of multiphase meters as a viable and necessary alternative to using test separators to separate oil, gas and water, before using single-phase meters to provide periodic measurements. In contrast, using multiphase flow meters can provide instantaneous, continual, real-time measurements to enable more accurate reservoir management, identify issues quickly and reduce financial exposure.
Due to diminishing conventional and easily accessed oil and gas reserves, operators are faced with the challenge of developing marginally economical fields. In many of these cases it is not economically viable to deploy bulky, costly, high-maintenance separators with accompanying flow lines and equipment. Furthermore, the shift to deeper wells with higher water content, along with subsea completions, gives greater urgency for multiphase metering solutions. Reportedly deploying a multiphase flow meter subsea can reduce capital expenditure by around 63%.
Multiphase meters play a critical role in oil and gas production. Not only are they used to quantify the amount of oil and gas produced for the purpose of fiscal taxation and allocation measurement of commingled pipelines but, due to their ability to provide real-time continuous measurement, they lend themselves to other critical applications. This includes well testing, which can be carried out more frequently than existing methods, reservoir and well monitoring to allow real-time management of the reservoir to optimise production levels. It has been said that the use of multiphase flow meters can increase recovery by up to nine per cent. Multiphase meters also play a major role in flow assurance through their ability to detect water, which can have a detrimental impact on production levels and plant and equipment safety.
Greater acceptance and field experience of multiphase flow meters over the last two decades has seen a rapid uptake from oil and gas companies. Installations of meters worldwide have grown three-fold in the last decade and are set to double over the next. A number of companies, cost permitting, strive to have multiphase meters installed on every well for production optimisation and flow assurance purposes. Recent years have seen significant advancements in multiphase flow metering, including improved accuracy and performance, more robust materials to cope with challenging subsea environments, and more compact designs to allow mobile monitoring. The next generation of multiphase meters using new technologies are in developmental and protocol stages and will soon be field tested and be commercially available. Meter manufacturers continue to drive down their measurement uncertainties to meet the demands of industry, especially for fiscal and allocation measurement applications. This will see the continued development and evaluation of multiphase metering technologies in the future.
Testing flow meter performance
There is currently a debate within the flow measurement community with regard to 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 offers 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 and gas poses particular difficulties when calibrating and testing flow meters, 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 flow meter 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.
Accurate meter calibration
When calibrating a device, it is a prerequisite that the value of the reference used is known with sufficiently low uncertainty, typically between five and 10 times lower than the expected uncertainty of the device being calibrated. Equally important is the temporal stability of the reference since its value was determined.
For example, consider the calibration of a balance, where an external reference mass is used to perform the calibration. The weight of this mass will have been determined by weighing on an appropriate system, which is traceable to national standards and ultimately to the primary kilogramme.
In this situation the reference mass is acting as a transfer standard. The material of the reference mass and its use (avoiding gaining or losing mass by careful handling) ensure that its value remains stable and known with low uncertainty. One would certainly not contemplate the use of a reference mass of unknown composition, perhaps covered in rust or worse still, likely to absorb significant amounts of water. However, this is effectively the situation of a multiphase flow loop, used to performance test meters using natural gas and live crude as the transfer standard fluids.
Fluid property issues
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.
Let us consider a typical multiphase loop operating with reference fluids, which include nitrogen, synthetic oils and a synthetic brine. A three-phase separator separates the gas, which is vented, and the two liquid phases. Each liquid phase is metered through its own reference flow meter and fresh nitrogen is added and metered through its own flow meter. Online density measurement of the liquid phases, combined with offline measurements of the pure liquids, enables the mass flow rates of the liquid phases to be determined and consequently 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.
Of course, this makes the assumption that all the gas (nitrogen in this example) remains in the gas phase and doesn’t absorb any of the oil or water. To test this assumption, we have undertaken a series of calculations by using thermophysical properties software that has a database of more than 1,400 pure compounds and a wide range of equations of state, which allow the properties of fluid mixtures to be calculated accurately.
During the tests, a fluid stream was set up to represent a typical set of conditions in the multiphase loop and the software was used to conduct a vapour/liquid/liquid flash calculation, to determine the amounts of each phase present and the compositions of the phases.
A calculation was also completed for pure nitrogen at the same temperature and pressure conditions and the density values compared. As shown in Table 1, the calculated densities were shown to differ by less than 0.1%, confirming the assumption that the nitrogen remains in the gas phase and doesn’t absorb liquids.
Data proves uncertainty
A similar set of calculations was performed with fluids representative of a live crude and natural gas. As the thermophysical properties software includes a petroleum fractions package, which contains pseudo-components such as crude oils, these can be treated by the calculation engine as pure fluids and mixed with other fluids from the system databank.
For this calculation a light crude with a specific gravity of 0.845 and a viscosity of 7.4 cSt at 100°F was chosen. A representative natural gas mixture was also used. As can be seen by the results in Table 2, 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, depending on whether a full vapour/liquid/liquid flash calculation was used, or whether the gas feed components were assumed to all remain in the gas phase from the gas reference flow meter to the device under test. Unless this partitioning is taken into account, the density difference calculated translates directly to an error in the calibration. These uncertainties can be of the order of several per cent, potentially ofthe same order as the required measurement uncertainty for the device under test.
It is clear, therefore, that for 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.
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 through sampling and offline analysis. Even if this approach is used inherent uncertainties still remain, arising from the equations of state. All equations of state require additional parameters (binary interaction parameters) to account for non-ideal behaviour of real mixtures.
The performance of different equations of state is very dependent on the availability of good binary interaction parameters (BIPs). In the software package used in our tests, the user has full control over the BIPs, but this is not necessarily the case with other packages. Furthermore, many packages adopt a ‘black-box’ approach, making it difficult to assess the impact of the calculations on the uncertainties of the fluid properties.
Temperature and pressure effects
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 such as 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.
This will not be the case if real fluids are used, however, 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.
Reference fluids improve accuracy
As research shows, the use of ‘real’ fluids such as natural gas, crude oil and brine increases the uncertainty on the calculated fluid phase properties. 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. It is for this reason that NEL has recently switched from using crude oil to refined oil as part of its 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. This document 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.
Published: 04th Mar 2015 in AWE International
