Overcoming oil & gas measurement challenges

April 30, 2015
High stakes and contaminated, multiphase fluids are met by a combination of purpose-built hardware and software
About the Author
Paul Studebaker is chief editor of Control. He earned a master's degree in metallurgical engineering and gathered 12 years experience in manufacturing before becoming an award-winning writer and editor for publications including Control and Plant Services.Upstream and downstream operations meet in the pipelines, where produced oil and gas are often metered to determine well productivity, assess production costs and transfer custody from producers to users. "Pipeline transportation companies need to know how much is being delivered and what inventory is in transit, to measure gas in storage and determine how much needs to be put in the pipe so the customer gets what they expect," said Dale Symington, senior product manager, measurement applications, Schneider Electric, in his session on Oil & Gas Measurement at the company's 2015 Global Automation Conference this week in Dallas.

"Pipelines transport very large quantities of oil and gas, and when you measure large quantities, small errors add up to significant dollars," Symington said. "Calibration and proving are important."

Variable composition poses challenges

Downstream products such as dry gas tend to be more valuable, but upstream products, which may contain a mixture of oil, water and/or gas, present the major measurement challenges. "Produced fluids are stuff that comes out of the ground.. We have to measure whatever we come up with—water, contaminants, sediments—stuff that can't be sold, but has to be measured to determine and allocate the costs of production."

"We have to measure whatever we come up with—water, contaminants, sediments—stuff that can't be sold, but has to be measured to determine and allocate the costs of production." Dale Symington spoke on oil and gas measurement at Schneider Electric's 2015 Global Automation Conference.

A flow measurement system typically consists of:
  • A "meter run" of pipe of known dimensions and properties;
  • A primary measurement device, typically an orifice plate, Coriolis, vortex or other flowmeter;
  • A transmitter or secondary device, for example, if with an orifice plate, a Schneider Electric 4102 multi-measurement transmitter that measures pressures and temperature;
  • An isolation valve to allow access to the transmitter for calibration;
  • Communications: cellular, IP modem, or local SCADA; and,
  • A SCADA host and data management system, typically in a remote location accessing many transmitters.

Flow computing software, such as Schneider Electric's Realflo, typically runs as an embedded package in a local controller, such as the company's SCADAPack 32, 330/334, or 350/357, or it may be included in the transmitter (as it is in Schneider Electric's model 4203). A companion configurator runs on Windows, typically in a laptop, to view, collect and export flow data. It includes wizards that help install, configure, diagnose and troubleshoot the flow measurement system.

Oil and gas are measured in units of volume, and volume varies by temperature and pressure, so flows must be calibrated and corrected to give accurate measurements at standard temperatures and pressures. A 100 °F difference in oil temperature results in a 3.5% change in volume, and gas volumes are sensitive to pressure as well as temperature.

So Realflo corrects oil volumes per API 11.1 and gas volumes per API 11.2.4, API 11.2.5. and AGA 8.

Data collection and computing

To deliver an auditable record, Realflo collects 35 days of hourly and daily data, as well as up to 200 well test records for each meter connected to the flow computer. (As many as four liquid or 10 gas meters may share one Realflo implementation, depending on the capacity of the SCADAPack.) Its configuration template is designed to handle complete setups, but with field access allowed only to the necessary information for field operations. Calibration logs are stored in accordance with API 21.1 for gas or API 21.2 for liquids.

Realflo stores as many as 300 alarms and 700 events over 35 days, with an auditable flow history of alarms and events so if necessary, users can reconstruct flow history after an event such as a lightning strike. A user-assignable database allows storage of additional information, such as casing temperature and pressure.

Even with the finest flow measurement equipment, "Production measurement of produced fluid is not fun stuff. It's difficult," said Symington. Fluid separators are often used to separate oil, gas and water, but "separation is never perfect," he adds. With a Coriolis meter, the flow computer can detect gas or water in oil and if it happens too often or for too long, it can notify operations to check the separator.

Realflo can be combined with Terminal Bus truck and rail terminal management software that runs in SCADAPacks, determines the amounts of fluids delivered, issues truck tickets and manages documentation.