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

The cost of building a production platform compared to the installation of a seabed MPFM has led to more multiple partner tiebacks. The commingling of different wells results in different well compositions, such as different types of salts in water, different types of oils (heavy vs light), contaminants (H₂S, asphaltenes, CO₂), different types of gases, different pressures and temperatures. Each MPFM is required to be calibrated to the specific fluid characteristics of each well. In tieback situations, to well test each well individually would require all but one well to be shut in at a time to achieve the most accurate results, albeit with the limitations presented above. Oftentimes in marginal fields, cash flow can prohibit such required shut ins. In deep and ultra-deep waters, to perform a well test would require a deep-water drill ship. Depending on the location, drill ships can cost up to US$1.5 million per day, not including the well testing service company.

Multiphase flow meters play a key role in optimising production flows and therefore boosting recovery factors. Accurate flow measurement near the well head enables users to make informed decisions about critical operational procedures such as; optimisation of obtaining reservoir characteristics, enhanced recovery techniques and the mitigation of pipeline flow assurance challenges. However, the use of multiphase flow meters in oil and gas applications is filled with challenges, such as:

• Will the meter still perform in a changed (more extreme) environment?
• Is the PVT model still representative years after installation?
• Are the fluid properties still the same over the years?
• Are we able to obtain a sample at the flow meter location (seabed)?

Over the course of the well’s lifetime, the pressure of the reservoir will decrease as hydrocarbons are produced. In the simplest case of a gas well (assuming constant temperature throughout the life of the reservoir), when the well was initially completed, it was a dry gas well. As the pressure in the reservoir decreases, the pressure of the reservoir crosses the dew point line and liquid can condense out of the gas. If the MPFM was not initially calibrated to account for liquid hydrocarbons, how accurate can the MPFM be in this scenario?

Another common occurrence in the lifetime of a well is water coning. Water coning happens when the well is pulled too hard, too fast and water from the aquifer below the pay zone gets sucked up into production. Was the water and the associated water properties accounted for in the initial calibration of the well? One of the benefits of using MPFMs in the case of water coning is that even if the now produced water was not accounted for in the initial calibration of the MPFM, an experienced MPFM user will be able to spot measurement anomalies from the real-time data and deduce that unwanted water is now present in the produced fluids. With this information, the operators can take the proper mitigating action (i.e. reduce drawdown pressure or perform a squeeze job).

MPFMs are commonly deployed in extreme conditions, enduring high pressures, high temperatures, highly corrosive contaminants, erosion, and heightened susceptibility to solid deposition. These variables, as well as the volumes of the primary fluids themselves, are subject to change over time and must be accounted for, in order to minimise measurement uncertainty.

A recent development in single-phase metering research has shown that Coriolis meters are indeed sensitive to changes in ambient pressures and temperatures. No such research to date has been conducted on multiphase flow meters, but through simple logic, it may be fairly assumed that MPFMs are indeed sensitive to changes in ambient temperature and pressures. Many of the challenges outlined above can be mitigated by analysis of a representative sample; however, can a representative sample be obtained?

Whilst ensuring that the ongoing performance of multiphase flow meters is critical to avoid the financial exposure and risks associated with their mis-measurement, to date, there is a need to address the challenges associated with their ongoing maintenance and calibration in-situ, for both topside and subsea installations. The effects of under reading and over reading on fiscal allocation can result in significant financial exposure, for example a 5% over reading on a water cut measurement at a 6000 bpd well reading leads to over US$20 000 per day loss for a single well. Heavier salt composition or heavier salt concentrations can lead to the perception that more water is being produced than in reality.

Even in the absence of major technological developments over the next 10 years, it will be important to investigate the finer details of multiphase flow in order to assess their impact on current MPFMs, but such knowledge will be vital for developing the next generation of MPFMs. As traditional calibration methods become increasingly unviable due to excessive cost and logistical problems, and as ever deeper and more remote fields are exploited, research work is also required to establish clear industry guidance. This will help to improve measurement uncertainty in the field, reduce financial exposure and increase confidence in the use and deployment of multiphase flow meters. A valid and fit for purpose in-situ verification method is required to ensure accurate measurements are obtained on an ongoing basis.

To this end, TÜV SÜD National Engineering Laboratory is 2.5 years into a 3.5 year long internal research programme that addresses the key challenges facing the global industry and aims to put in place various measures and practices to help reduce their impact.

In-situ verification will still require either a comparison with another flow measurement system or the use of diagnostics to estimate the quality of the measurements being taken on a continuous basis. Numerous options have been evaluated so far, with some showing real promise and demonstration of a minimum viable product complete.

A commercially available MPFM was installed at the company's laboratory’s multiphase facility, with real time data acquisition and processing (including data output from secondary instrumentation) using the facility’s proprietary validator software. This software plotted, in real time, the output of the MPFM, allowing the performance to be easily verified through the delivery of a pass or fail result based on a comparison between the MPFM and the physical or virtual reference. Progressing towards a robust in-situ verification method allows a significant reduction in cost and reduction in measurement uncertainty from using multiphase flow meters, reducing financial exposure and confidence in measurement.

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

Read the article online at: https://www.oilfieldtechnology.com/special-reports/23012020/why-traditional-methods-of-validating-multiphase-flow-meters-are-not-delivering-part-two/