Measuring multiphase flow

Over 10 000 multiphase flowmeters (MPFMs) have been purchased by the oil and gas industry over the past three decades, which constitutes a significant investment in sensing and measurement technology. This investment is not squandered, and has been shown that accurate and timely production flowrate measurements can help to optimise reservoir long-term recovery, as well as being more economically beneficial. But what are MPFMs, how have they been used in the oil and gas industry, and more importantly, how can we have confidence in the measurements they provide?

Multiphase flow

Multiphase flow is the simultaneous flow of different fluid phases within a pipe or flowline. In the oil and gas industry, this typically represents the flow of liquid hydrocarbons, liquid water and gaseous hydrocarbons all together in a dynamic mixture. The two liquid components are immiscible, with water usually having a larger density. Gravity attempts to separate the fluids into their three distinct regions, but the energy from the flowrate and physical installation enables mixing of all phases together into various distributions called flow regimes.

The different magnitudes of mixing and separation result in several flow regimes being possible with one dominating under specific process conditions. For instance, at lower flowrates, separation usually dominates, and the individual components flow in distinct regions within the pipe, i.e. water on bottom, hydrocarbon liquid in middle with gas on top (separated by increasing density). At higher flowrates, the fluid could be extremely well mixed and flow as a homogenous mixture. To further complicate the situation, the quantity of each phase is important too – if there is more liquid than gas, flow can be described as bubbly; if there is much more gas than liquid, then the process is described to be a wet gas with droplets of liquid in a gas continuous phase.

This demonstrates just how challenging the measurement of multiphase flow can be. There are a great number of variables to account for and considerable practical constraints to include, such as contaminants and impurities. Many manufacturers of MPFMs have risen to meet the challenge by designing topside and subsea modules to provide their best estimate of production flowrates.

Real-time monitoring

Before the widespread implementation of MPFMs, and still in place today where they are not installed, well production rates are monitored by periodic well testing. This involves the use of a test separator and the well under test being directed to it for a short period: around 2 - 3 days depending on distance from facility. These systems are usually accurate if properly maintained, however, the main drawback is the periodicity of the test. If a well increased water production between well tests, this would not be picked up until the next well test. This leads to production inefficiencies and increased costs.

Real-time monitoring of wells is therefore of considerable importance to controlling, and more importantly, optimising production rates. MPFMs play a critical role and have enabled end users to improve performance. Aside from improving production rates, further benefits of measuring multiphase flow in real-time can be observed from how the data is used and what decisions can be made based on the values. Production rates are sometimes used for allocation measurements, i.e. adjusting flows in comingled systems, and are the basis of how much a producer gets paid for their fluids. The impact of inaccurate measurement in this instance is clear as financial losses are more clearly evident.

Verification

With advances in technology and changes in oil prices, it is becoming more economically viable for smaller fields that were once too costly to produce to come online through the use of tiebacks. MPFMs play a vital role in these instances as they enable monitoring and control, and sometimes allocation of produced fluids where there is little infrastructure to employ a more traditional method e.g. a test separator.

It is clear that MPFMs have provided a valuable tool for industry to improve their operations. However, like any measurement technology, it needs to be verified in order to trust the results that it gives. The most common way to verify an MPFM currently is by using that same infrastructure that it replaced – the test separator. This time, the periodic nature of the test is not a major issue as the measurements are still being undertaken in real-time during operation. This method also helps alleviate the stress on a test separator used when no MPFMs are present as it is normally constantly in operation, leaving little to no time for verification of its own measurement sensors. With less time constraints it is easier to ensure…

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