Offshore and Onshore Flow Metering Systems – Part III
Offshore and Onshore Flow Metering Systems – Part III Chapter Five – The Shock of the New By the mid 1990s, the phrases ‘fit for purpose’ and ‘cost reduction’ hit the Oil & Gas projects.
Offshore and Onshore Flow Metering Systems – Part III
Chapter Five – The Shock of the New
By the mid 1990s, the phrases ‘fit for purpose’ and ‘cost reduction’ hit the Oil & Gas projects. Traditional metering stations with relatively high CAPEX and maintenance costs. But let’s not forget that companies were still paying tax to governments and receiving payments for sales, depending upon the accuracy of the flow-meter readouts. Cost reduction definitely did not mean accuracy reduction.
Almost simultaneously, the first of the new electronic inferential meters with the power of digital processing hit the oil market. These were the multi-path ultrasonic flowmeters (UFM) and the coriolis mass flow meters. The UFM principle was already established in the large-scale water industry. It also promised to replace orifice gas flow metering. For simplicity’s sake, permit me to continue to ignore the huge gas metering side of our business.
The ultrasonic flow meter found an immediate market just waiting for it in the very new FPSO (Floating Production Storage & Offloading) vessels that came into operation. These vessels took the place of purpose. They made oilrigs for a fraction of the cost, and in a fraction of the construction time. This made them most attractive for ‘early oilfield production’.
Everything happened fast. On the open-seas, FPSO required high speed offloading flow rates to limit the time (and the risk) ‘at station’ whilst loading. The typical pipe sizes were 20”nb (400mm) at perhaps up to 5000 m3/h (750,000 BPD). The pumps did not like high-pressure losses and often produced ‘mixed’ oil quality. UFM meters became more accurate with increased ultrasonic path length and therefore pipe size, and mostly with a pressure loss no more than the 15D to 20D pipe lengths required for flow conditioning & accuracy.
Above the transition region where laminar flow becomes turbulent, rangeability was very good. Almost all pipe flow offshore was turbulent. Thus, 0.5m/s to 10m/s oil velocity became a de-facto standard (turndown 20:1) for a well-sized ultrasonic flow meter installation.
Early meters were not so accurate or repeatable with small proving volumes. However, they soon advanced in the electronics and transducer design to full fiscal or custody standard. Since UFM are flow-velocity averaging devices, and, like turbine meters, initially susceptible to swirl, flow-profile, density and viscosity changes, as well as water-wax-gas inclusions. They were also viewed with suspicion by traditional metering engineers, much like small volume piston provers.
Offshore bi-di pipe provers had a practical limit around 30”nb loop size, or around 2345 m3/h (350,000 BPD). This meant that one could only prove UFM up to around 12”nb.
You still with me? …Good.
To move ahead with the ultrasonic flow meter, we needed another proving method. This arrived with the wider acceptance of ‘master meter’ proving. This abandoned the volumetric prover device in favor of a secondary flow meter, deemed a ‘master’, which could be connected in series with the duty meter. In this arrangement, the quantity of the prove-run was unlimited. This extended the period of proving considered. This was a super idea since inferential meters become more accurate and more repeatable as the sample size increases.
To complete the scheme, one installed the master meter in a so-called ‘Z pattern’. This separated it from disruptive temperature and pressure fluctuations, as well as the erosion/corrosion of the flowing oil. It was used regularly in series as a ‘master meter prover’ or in emergencies, even as a backup spare meter for a failed duty unit. Many continue to accept this solution as a custody meter station installation in many new offshore projects.
Master metering is not a new idea, but its adoption for custody metering stations is. No one argues that the volume prover is more conventional…even traditional… but it is not appropriate for many offshore instances. Other techniques are less expensive and more practical in size and weight.
Chapter Six- The New Kid on the Block
Earlier, I gave only scant mention to Coriolis mass meters. These were arguably the last of the great flow-metering principles to become accepted, and are often called ‘the best kept secret’ of the Oil & Gas industry. One of the earliest offshore fiscal stations exploited the fact that Coriolis meters are hard to break. The project had mixed crude oils and temperatures ranging from 60°C at production to 4°C at the sea-floor storage tank. This lead to a range of viscosities from 20cP to 1800cP. The use of PD and turbine meters reduced. Due to the problems offshore, ultrasonic flow meter was not yet acceptable or available. However, the Coriolis meters could handle everything, even if the accuracy might be questionable under difficult conditions. A small volume piston prover was used for calibrations, arranged with vertically down-flowing oil, to allow any contaminants to ‘wash’ out of the bottom in normal use.
This is not a technical report, and there are plenty of explanations for this in other papers. Suffice to say that the molecular mass of the fluid passing through them directly affects Coriolis mass meters’ output. External excitation of the fluid by the instruments electro-mechanical transducers causes a ‘coriolis force’ that is measured in the meter and is converted into an ‘observed mass flowrate’ output signal. This is quite unlike a UFM, which is a velocity-averaging device. However, the flowrate processing does share similarities with the UFM. For this, a specific time interval of flow rate sampling is also necessary.
Sizes in its earliest ‘teenage’ days were very small, with a maximum of 6”nb. But now the instrument has grown up, to 12”, 14” and even 16” flange sizes. Of course, this is still far below an ultrasonic flow meter that has no practical limit. However, one must first investigate the aspect of proving uncertainty before settling on another principle.
Firstly, there are now small volume piston provers that can prove the largest mass meters available. These do seem practical for offshore use. But these are still large and are generally several times more expensive than the meters they prove. Of greater interest is the same master-metering method that has found favor with the offshore UFM.
Next Tuesday we will kick it off with the last part of our journey if you want to see more from this author take a look at his LinkedIn!