Why traditional methods of validating multiphase flow meters are not delivering – part one

The ability to provide real time measurement of unprocessed hydrocarbons has led to a greater uptake in multiphase flow meters worldwide. Multiphase flow meters (MPFMs) provide continuous real time measurement of unprocessed hydrocarbons and from the mid-1980s they have been used for oil and gas production optimisation, hydrocarbon allocation and to control the technical integrity of oil and gas production facilities. Traditionally, flow is measured to distribute produced assets fairly among each proprietor, but more recent advances in technology have enabled measurement devices to be applied to additionally important applications, such as well productivity and reservoir performance monitoring.

Currently, it is estimated that there are more than 6000 MPFMs in use globally, with field operators using them to reduce capital and operational expenditure and to increase production efficiency. Some of these meters are installed within existing infrastructure (e.g. test separator), while others are being used as the primary measurement point for new fields or to realise cost benefits in the exploitation of marginal fields. Multiphase flow meters play a key role in addressing well performance by measuring the well rates and ultimately increasing the reservoir final recovery factor. Accurate flow measurement near the wellhead enables users to make informed decisions about critical operational procedures, such as optimisation of reservoir characteristics, enhanced recovery techniques, first water break through, and the mitigation of pipeline flow assurance challenges.

However, unlike single phase meters, due to cost and installation issues, there is no expectation that a MPFM would be returned to a calibration facility on a regular basis for calibration. Traditional validation methods, such as well testing, are often viewed as less feasible due to their excessive cost and large associated infrastructure. Also, modern production alternatives such as subsea processing, where the expectation is that they are installed for permanent and continuous use, make the use of these traditional verification methods much more complex.

Well testing requires a huge footprint and causes disruption in production, typically requiring the use of a service company at a cost of tens of thousands of US dollars per day. Well tests can also take up to several months, depending on the objective of the test. Often during these tests, because perfect separation is not achieved, the gas produced is flared off, thus increasing the carbon footprint and, in some cases, requires special permits. Because of subsea tiebacks, well testing might take place literally miles away from the subsea well head and therefore there will be an increase in pressure drop between the test and the well head. This leads to further challenges which needs to be considered:

• Are the PVT and properties at the well head / MPFM still representative?
• Has more gas escaped from the liquid phase and entered the free gas?
• Has hydrocarbon liquid dropped out of the gas and entered the oil phase?
• How can these be accounted for in the upstream MPFM?
• How are commingled wells (in the case of tiebacks) dealt with?

In large-field production, several wells may produce to a common separator with the resulting single-phase streams commingled into a common transport pipeline with streams from other separators or facilities. Total flow rates are measured downstream, meaning the contribution from individual wells is not known, leading to additional challenges that need to be addressed. Well tests are always performed at pressures and temperatures much lower than the line conditions of the MPFMs, again raising the question of PVT representativity.

Most traditional single-phase measurements taken in a well test are based on volumetric calculations, which are subject to change with varying temperature and atmospheric pressure; whereas for most MPFMs, measurements are based on mass rate, which are not subject to these variables. Mass versus volume-based measurements require careful consideration over which PVT model to use to convert mass flow rates to volumetric flow rates, or to pass from line conditions to standard conditions. Also, traditional well tests do not achieve 100% separation, therefore data acquisition systems require continuous input of oil in water and water in oil contamination. Moreover, the total gas oil ratio is typically not fully measured in a well test, therefore the gas flow rates of an MPFM can’t be reliably validated.

When appropriately calibrated, MPFMs are better than well testing; they provide mass-based measurements which are not subject to changes with varying pressures and temperatures, and measurements are performed as close to the well head as possible, in some cases, even upstream of the choke. The introduction of multiphase flow meters requires a fraction of the construction costs of a production platform. However, they still require appropriate calibration, in many cases several years after they have been installed. To achieve this, cross correlation is required between the well test and high pressure MPFM measurements, stepping non-uniformly through potentially shifting PVT diagrams. This will become an ever more significant issue as industry continues to exploit deeper and more remote fields and with the tiebacks of marginal fields owned by different companies to a main production line.

This is part one of a two-part article. Part two is available to read here.

Read the article online at: https://www.oilfieldtechnology.com/special-reports/22012020/why-traditional-methods-of-validating-multiphase-flow-meters-are-not-delivering-part-one/