Offshore and Onshore Flow Metering Systems – Part II

Flow Metering System

Chapter Three: Space – The Final Frontier

Early on, people called Gulf rigs ‘lily-pads’. The traditional meter stations barely fit on the structures. The flow meter process offshore was either very unsophisticated  or simply carried out elsewhere.

David Potter’s work in the 1940s for the new US Navy jet aircraft fuel systems promoted ‘turbine flow meters’ in the oil business.  The new turbine meter design ‘inferred’ the average volume flow rate of oil, based on the kinetic energy absorbed by the blades of a rotating turbine.  This allowed the turbine meter to be very small for its capacity – ideal for an aircraft – but also ideal for offshore oilrigs. 

Unlike the positive displacement meter, any ‘spin’ of the oil in the pipe affected the turning rotor. This includes anything significantly out-of-symmetry in the flow-velocity profile approaching the blades.  This meant that upstream and downstream flow conditioning was necessary to ‘standardize’ the turbine meter results. This added around 15D (15 pipe diameters) of length to the installation, and also a little more pressure loss. But this was no more than that of most positive displacement meters.

Positive displacement flowmeter
Courtesy of Visual Encyclopedia of Chemical Engineering

A hydrodynamic bearing minimized bearing friction. This is a fancy name for the same bearing you have on the piston crank of your car engine.  When running at speed, the rotor actually ‘floats’ on a wedge or layer of oil molecules that has minimal drag and minimal wear. This is a very elegant design that works with most liquids that are not too ‘thin’. In other words, those with a reasonable density and viscosity.  In general, the filtration required had to prevent larger particles from lodging in the gap between the rotor and the casing and was typically rated 10 mesh (2000 micron).

Although prolonged dry running (gas) would cause damage, unlike the positive displacement meter, occasional gas inclusion would not. It just affects accuracy.

One big advantage is that the spinning rotor has inertia and momentum. This means that in most cases, it ‘averages-out’ sudden but transient flow changes, giving it very good metering repeatability.  On the other hand, although it can handle wide flow ranges without damage, the linearity of turbines is only good in a limited range. Typically, 3:1 ‘premium’ and 10:1 standard – still pretty good. 

Chapter Four: Prove it!

In light of all the above activity, turbine flow meters became the most prevalent type offshore. This lasted until the end of the 1990s.  But the turbine meter (like the positive displacement) still requires regular proving. Traditionally that has meant a large volume pipe prover that gathered at least 10,000 pulses during a prove. Bi-directional pipe provers developed to reduce the size. The pulses from a ‘forward’ run combined with those from a ‘reverse’ run to make 10,000 for a prove. This had the additional benefit of reducing detector errors, possibly caused by single direction operation (hysteresis, tolerances etc.). Dimensions of bi-di were much less than uni-di, but the weight was probably similar!

turbine meter
Courtesy of Gpiflowmetersuk

In the 1980s, small volume piston provers arrived.  Pulse interpolation techniques (eventually incorporated into API standards) developed to reduce detector uncertainties to within acceptable limits. Standard pipe provers then developed to incorporate those same techniques. As a result, the turbine meter produced less than 10,000 actual pulses. This reduced the size of the pipe provers (sometimes known as small volume provers).

Why not just use small volume piston provers offshore and gain benefits on both size and weight? A good question, easily answered. First, the oil industry is very (…very) conservative and traditional. Pipe provers were familiar to all metering engineers. Many considered the piston provers ‘new-fangled’ things, with electronics and ‘electro-hydraulics’ and even pneumatic components.  Secondly, the early units were precision instruments with a highly polished measuring ’barrel’ and a piston with critical PTFE seals that did not tolerate dirt. Finally, vibration, shock, and surges – wherever they came from – easily upset their short piston movement.  It made them ideal devices onshore, but less so for offshore purposes.

And so my friends, things went on like this for a couple of decades. Turbine meters slowly took dominance over positive displacement meter, with bi-di provers permanently installed on the platforms.

Got hooked? To find out more, join me next week for the third entry of our four-part discovery on Flow Metering Systems.

Interested in this author’s work? Follow him on LinkedIn!

Related tags: Flow flow measurment Flow Metering System Offshore Oil & Gas Onshore Positive Displacement Positive Displacement Meter Turbine meter
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