When the concept of multiphase metering was first suggested, it became apparent that this was a game-changing technology:

A multiphase meter can eliminate the need for a test separator;

Because test separators are big and difficult to maintain, eliminating the test separator makes smaller platforms possible;

Existing facilities can be upgraded to take subsea tiebacks without having to add an extra test separator. The test separator can be reused as an additional production separator to cope with the extra output;

Commingling and long pipelines often make test separator measurements a fairly poor indication of individual well production;

Multiphase meters give continuous measurements, allowing better reservoir management and quicker response to water breakthrough and similar events; and

Having a subsea multiphase meter on each wellhead

facilitates the use of multiphase pipelines.

In general, multiphase meters open the door to development of marginal assets and promote more efficient exploitation of larger fields.

In its flow measurement facility, NEL carries out its responsibilities for the provision and maintenance of the UK’s national standards for flow measurement. (Images courtesy of NEL)

How they work

Basically multiphase flowmeters consist of a number of sensors connected to a processing unit that derives the flow rates of each fluid. In principle, if operators make several separate measurements, they can measure the flow of all three fluids in the same pipe. The art of multi-phase flow metering is in the selection and optimization of the sensors and in the combination of their raw data to give an accurate measurement.

Various processing approaches have been used, most of which require a detailed understanding of the physical processes within the pipe. However, neural network approaches also have been used where the flowmeter “learns” how to derive the flow rate over a set calibration period.

Different sensing methods also have been used in multiphase flow, ranging from differential pressure devices to gamma densitometers, capacitance and microwave sensors, and ultrasonic sensors.

Over the past few years many commercial meters have adopted a similar strategy. These days most include a blind-tee or a similar mixing element, a Venturi, a densitometer, and capacitance measurement. This convergence to a particular design is a practical solution to current requirements.

However, future needs and new approaches are likely to lead to the development of radically different meters that will work in parallel with or even replace current technology.

Taking the technology subsea

Multiphase meters are reasonably well accepted for allocation and reservoir control purposes when installed on surface wellheads. The use of multiphase meters subsea, however, is a more challenging proposition and a subject of much ongoing development.

When installing a multiphase meter subsea, the three “Rs” – reliability, redundancy, and retrievability – become crucial. As subsea interventions are significantly expensive, it is highly desirable that a multiphase meter can function for long periods of time – as long as 20 years or more – before maintenance.

Also, it is often forgotten that the primary function of a flowmeter is to contain the flow, not to measure it. Hence, performing erosion and corrosion testing and analysis is essential for a subsea metering installation.

NEL was recently involved with the Research Partnership to Secure Energy for America (RPSEA) on a research project in which sand erosion was assessed for different multi-phase meter configurations. This showed a large difference between different meter designs and indicated that each case should be considered on an individual basis.

Multiphase meters need good information on fluid properties to produce accurate measurements. Subsea sampling was achieved as long ago as 1997 in the ETAP development in the UK sector of the North Sea, but it still remains a major challenge. Extracting a representative sample of the produced fluid from a live stream is not straightforward. Transporting it to the surface while maintaining its pressure and temperature is difficult, and even handling and processing it on the surface presents major safety implications. Currently a number of techniques are being developed. Also, new metering approaches are being used in which extra meter measurements can minimize the requirement for sampling.

In the CFD simulation of a control valve, the colors predict the areas more susceptible to damage by sand. The red areas are more susceptible to damage while the blue are the least susceptible.

Heavy oils

Most of the remaining oil reserves in the world are classed as heavy oils. Most modern multiphase meters have been developed for use with oils with viscosity similar or slightly above that of water (about 1 centipoise). Heavy oil can have a viscosity of 10,000 centipoise or more, and this is likely to be highly sensitive to temperature.

Test and computational fluid dynamics (CFD) work carried out at NEL in conjunction with a major meter manufacturer has shown that most conventional multi-phase meters need to correct for the effect of liquid viscosity in heavy oil applications. Again, this requires either good sampling and characterization of the oil or a measurement method that is insensitive to oil viscosity. Similar issues apply when emulsions are present, and the ability to handle with emulsions will become more important in the medium term. Most multiphase meters come in the form of fixed pipe sections between two flanges. New clamp-on metering methods have come onto the market over the last few years. These meters are likely to find retrofit and temporary applications and could potentially supplement current metering techniques. The RPSEA project is developing a concept for an ROV-retrievable clamp-on subsea multiphase meter that could be used to verify or replace existing technology.

Measuring flow downhole

Traditionally, downhole flow measurements have been made on a one-off basis (e.g. wireline logs), and they have been used for reservoir characterization and management purposes. Fiber-optic cable now can be installed in wells with numerous embedded measurement points along its length (usually Bragg gratings), which permits a large number of continuous pressure and temperature measurements to be made along the length of the well. Single-point transducers using other technologies are increasingly being installed in wells to measure flow, water cut, and other parameters, and in the future many more downhole measurements will be taken. These could supplement or replace traditional multiphase meters.

Partly as a development of downhole technology, “virtual flowmeter” technology has emerged. Virtual measurement employs software that combines distributed measurements to calculate the flow rate. For example, the pressure drop across a choke, the wellhead temperature, and the downhole pressure could be used as inputs. These systems can be used easily with existing infrastructure, and in the future they could eliminate the need for additional hardware.

Well and pipework flow simulation software also is being integrated with these systems, and the resultant real-time modeling will offer major opportunities for understanding and optimizing production systems.