Liquids measurement in the oil patch is suddenly getting a lot of attention. Some are dismayed at the low level of technology used to measure liquids. Today, custody transfer of 80 to 85% of onshore crude and condensate production is still documented by a hauler climbing to the top of the tank and strapping it. “That would be a fair estimate,” concurs Mark Davis Staff Engineer Shell Exploration and Production. The hauler straps the tank before loading his truck and again when he finishes. The producer is paid on whatever that hauler writes on the ticket.

“I did not realize it was that immature,” remarked Grant Farris, Vice President Producer Services, CIMA Energy.

So, why it is that immature? Simple, really. The United States is experiencing the highest level of active liquids exploration and production in 40 years. Five years ago finding an oil play at NAPE was almost impossible. While the industry was diligently automating gas measurement to the digital world via electronic flow measurement, oil at $30/bbl and 15bbls/day was not given the same level of attention nor effort. These dynamics have changed.

The characteristics of produced fluid at the wellhead is just the first hurdle to accurate liquids measurement. Full well stream production is a very complex combination of oil, gas, condensate and/or water. Measuring any one of these components accurately is difficult. In combination, they make liquids measurement a real challenge. Furthermore, the produced fluid may undergo 2 or 3 phase separation or no separation at all. These facility design decisions dictate the measurement solutions available and the degree of accuracy to anticipate.

A typical production scenario has the produced fluid brought to the surface then processed through a 2 or 3 phase separator. The result is gas goes to sales or gas-lift, water and oil goes to their respective tankage. If a 2-phase separator is used, the gas goes to sales and the oil and water combination goes to tankage for gravity separation.