Offshore and Onshore Flow Metering Systems – Part I

Chapter One: The Journey of the Fellowship Commences

To begin our journey on flow metering systems we are going to ask ourselves a question: Why the hell would anyone get oil offshore when they could get it onshore? The simple reason is that they don’t have a choice. To understand this, we’ll have to go over a bit of history….Back in the 1930s, everyone was searching for a bit of land from which to take the ‘easy oil’ just under the surface – which cost about $0.05 a barrel.  When all the available land was ‘acquired’, the search went offshore.

They found the easy stuff in lakes in the Caspian region, or in the Gulf of Mexico.  But in Europe, the only water was deep. At that point, the dream of North Sea oil began.  By the 1970s, oil began to flow, but in deep waters and 400 km offshore it was said to cost around $100.00 a barrel for ‘early production.’  Things have settled down now, but why is this process so expensive? There are three main reasons for this, and these are all shared with 1970s space exploration (…Yes, really). 

The first reason is safety or risk

It is quite dangerous to operate heavy drilling and production equipment with real people on the open sea. The protection systems for safe operation are very similar to those for space exploration. Okay, the order of magnitude may be very different in space, but there could be a hundred individuals working on an offshore drilling platform instead of just two or three.

The second reason comes down to weight

Just like NASA, oil companies have to pay for every kilo of steel, aluminum and human labor they transport to high-seas locations.  Keeping all these elements upright, stable, and floating for some 10-20 years costs real money. In early days, when one man came onboard, another man had to leave!

The third reason is the return

Returning astronauts safely back to Earth requires an enormous amount of infrastructure– easily as much as what takes them out there in the first place. 

In the 1970s, oil companies paid taxes to the government for all the oil they raised to the surface. Then, oil was a national asset that belonged to all people. However, Oil & Gas does not make a single penny until oil is returned to shore. 

Originally, shuttle tankers transported the oil to shore. However, it was very dangerous to load them on the open seas and they had a very limited capacity.  Later, undersea pipelines were laid at an enormous cost – this was so expensive that the capital costs were mostly shared by several oil companies working in the same area.

All the above reasons underscore why the development of offshore Oil & Gas flow metering is so critical.

flow metering system - diagram offshore oil transportation
A diagram explaining a modern method to transport oil to the shore, courtesy of siphonophores

Chapter Two: Size does Matter…

At first, weight and size hardly ever affected land-based oil production. As a result, the traditional onshore flow metering systems were huge and complex.  In early days only oil was measured, and gas considered a waste product, was burnt in the atmosphere.

It’s not a big surprise, since every unit of the liquid hydrocarbon has an energy value many times greater than the gas form, that they used it for more than just fuel – for example in lubricants and petrochemicals.

Positive displacement (PD) meters measured oil flow, which loved heavy oil with its lubricating qualities. The relatively high viscosity worked with the PD meter to make a better seal between the rotors and the meter casing.

PD Meter and accuracy!

Accuracy was good by any standards. Though some of them were relatively complex, the principle and the internals were mechanically simple for the engineers of the 1900s to understand.  How accurate was it? Well, let’s say it had a budget of ±0.5% of reading at 95% confidence for observed volumetric flow measurement. So…not bad at all.

But the accuracy of the PD meter depended on the following four major points. The first was the need for a fine filter/strainer upstream to protect the delicate rotor seals from damage.  Secondly, an air-eliminator was necessary to avoid the rotor from surging and miss-measuring, due to the sudden difference in the densities of liquid and gas. 

Positive displacement flowmeter

Thirdly, the liquid had to be self-lubricating to avoid rapid wear on the precision rotor seals.  And finally, since all rotating meters were in normal use, they needed regular checking and re-calibration (or in American English, ‘proving’).

Quite separately, the PD meters were ‘instruments’ that required careful handling and maintenance by specialists.  For example, some said that the heavy rotor of some designs could vibrate at a resonant frequency of adjacent heavy diesel equipment (like winches). This could cause ‘brinelling’ and failure of the bearings, so they normally utilized solid heavy foundations to attenuate the effect.

After all these requirements, the ‘metering stations’ (as they called them then) became large and heavy packages. If they permanently installed a prover, it was traditionally a huge uni-directional pipe sphere prover. It was also normally much larger than the meter station itself.

Now we move offshore. Here, I’m making the wild decision to ignore very early installations such as the 1891 ‘Grand Lake St. Marys’ shallow water rig. Instead, let’s concentrate on the Gulf of Mexico, post-1947. Here, Kerr-McGee made the first oil discovery ‘out of sight of land.’

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

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