Flows have been measured since ancient times, of course, but once those early, open-air irrigation ditches, canals and aqueducts gave way to stone, wood, brick, ceramic, metal and other enclosed passages and pipes, it probably took their users about two minutes to begin seeking the paddle wheels and mechanical, mass, magnetic, ultrasonic and other flow-sensing methods they've been using ever since.
While these technologies and their ongoing refinements receive the majority of the applause, they've each been aided in recent years by increasingly quick, small, powerful and inexpensive microprocessors, more competent software, and other on-board intelligence formats and supporting devices. They can perform flow-related calculations out in the field or on the edge, or access and cooperate with fieldbus, Ethernet, wireless or other networks near and far.
To examine the preferences of some of its flow measurement readers, Control polled about 150 as part of its March 2017 market intelligence report, "Temperature, Level, Pressure and Flow." As might be expected, differential pressure continues to be most used, followed by Coriolis, as well as electromagnetic, vortex shedding, venturi tube, multi-port pitot tube, thermal dispersion, turbine meter and insertion at the lower percentages (Table 1) .
Managing metering—and bubbles
No doubt the most significant result of flowmeters gaining on-board intelligence and networking is the new jobs they can take on that they couldn't do before, or would have to rely on other devices to do. For instance, Bonanza Creek Energy Inc. in Denver, Colo., recently needed a more accurate way to measure the oil, liquids-rich natural gas and water its lateral wells were producing in the Denver-Julesburg Basin, which is being developed with horizontal drilling and multi-stage fracture stimulation. The company had been using traditional tank gauging to measure each well's production volume, which is simple and relatively accurate, but is also time-consuming, costly and carries some safety risks.
To account for production variations among the wells and provide accurate well allocation measurement data, each well on a pad had to flow into a separate tank. As a result, Bonanza Creek's engineers sought a cost-effective way to provide an accurate oil meter at each wellhead, where the oil flows into a separator that separates water, gas and oil. They also anticipated there would be gas entrained in the fluid coming out of the separator, so they needed an entrained gas management (EGM) option, too.
To fulfill these requirements, Bonanza Creek's team worked with representative I.C.S. Sales to evaluate and eventually adopt Optimass Coriolis mass flowmeters from Krohne Inc., which reliably identifies gas bubbles with a combination of measurements that detect two-phase flow. Optimass detects and indicates entrained gas, and maintains active measurement in all measuring conditions with gas content from zero to 100% by volume.
Optimass models deployed by Bonanza Creek vary depending on the accuracy required by different wells according to their location. Private leases use Optimass 1400, which offers a published accuracy of 0.15%, while Optimass 6400 with 0.10% accuracy is used for U.S. Federal Bureau of Land Management leases. In addition, Optimass 6400 is approved for custody transfers of liquids and gases, making it suitable for process industries and special applications, such as LNG, CNG or supercritical gases in terminal or storage/bunkering and/or custody-transfer applications (Figure 1).
The flowmeter's measuring sensor and signal converter provide complete digital signal processing from the drive oscillation of the measuring tube to evaluating sensor signals. The meter continuously measures mass density, and provides measured values at all times. At the same time, it can report two-phase status, and output a preconfigured alarm in accordance with NAMUR NE 107 requirements.
“We knew this new technology would be the best way for Bonanza Creek to handle entrained gas, and the demonstration showed them clearly how the meter could help,” said Bob Phagan, technical sales representative at ICS. He added that Optimass flowmeters are installed on the crude oil leg of Bonanza Creek's oil/water/gas separator. Less costly technology meters the water because it's less valuable, and gas is metered using differential pressure (DP) devices.
After buying its first 30 flowmeters in 2013, Bonanza Creek compared its tank volumes to metered volume over 24 hours, and found only minor differences, which were due to shrinkage. Since then, Bonanza Creek has installed more than 400 Optimass meters, which lets it accurately manage wellhead allocation, and give stakeholders critical production data.
"Ever since microprocessors were incorporated in Krohne devices, we've embedded some form of sensor intelligence," says Joe Incontri, marketing director at Krohne. "Today’s high-performance flowmeters feature advanced diagnostics that are delivered to users via onboard web servers in the form of a browser-based graphical user interface, which can be viewed on any device, locally or remotely. It should also be noted that, while instruments are smarter, they can also interface with users much better as well. PC-based configuration and troubleshooting software like PactWare can help users easily navigate all built-in diagnostics with ease.
"Our most striking example of onboard intelligence is probably the EGM feature on our Optimass Coriolis mass flowmeter. Its microprocessor can control sensor oscillation regardless of the fluid state in any two-phase flow condition. While EGM is a feature that's turned on right out of the box, other diagnostics features must be activated in the field by the user. My recommendation to users is to look at the available parameters in their devices, and consider them for optimizing operations or their maintenance cycles."
Low power, software support
Though internal microprocessors and Ethernet/Internet links emerged gradually in many field instruments and in process control, most users and developers have come to view them as increasingly indispensable—but they still need power and supportive software.
"Every end device now has a microprocessor. We use ARM-based chips, and the key is low power, as well as computational capability and the right firmware," says Srikanth Mashetty, engineering manager for the Oil and Gas division at Rockwell Automation. "Our sensors on the upstream flow side are usually in remote locations, so there's less chance for them to get power and they often need wireless. For example, in extended downhole monitoring applications, they're going to need a low-power system to take surface pressure data, back-calculate the flow and bottom-hole pressure, and report by exception to save power."
Mashetty adds that some embedded data processing tasks are getting easier as the chips and networks get more capable. "In the past, they mainly did analog-to-digital (A/D) conversion to help devices like transducers convert their pressure signals to digital signals, so they could send them over the network," explained Mashetty. "Now we have market-leading microprocessor companies such as Intel and AMD investing in making more capable chipsets for remote sensing and bringing the Industrial Internet of Things (IIoT) to edge devices in a secure and scalable fashion. Some of these chipsets, like Atom and Cortex, which is in our iSense GP wireless sensor, are making their way into oil and gas automation applications."
One particular incentive for adding intelligence is to reduce billing delays and inaccuracies in hydrocarbon transfers from lease automatic custody transfer (LACT) skids, such as those operated by Ted Hutto and Ronnie Riggs, who co-own two companies, Panhandle Meter Service and Trigg Technologies (www.triggtechnologies.com), both in Pampa, Texas. “Customers across the board struggle with ticketing errors resulting from poor handwriting or spelling,” says Hutto, who adds that only a few LACT units are semi-automated with a touchscreen, onsite ticket printing, or links to a SCADA system. “And sometimes, key information isn't filled in on the ticket.”
To improve its LACT operations, Trigg worked with Rockwell Automation to develop a turnkey asset performance management (APM) solution using Microsoft Windows Azure cloud platform. Data from the LACT's Allen-Bradley CompactLogix programmable automation controller (PAC), an Endress+Hauser (www.us.endress.com) Coriolis mass flowmeter, and a sediment and water detector are displayed on a local HMI or industrial PC screen and transmitted into the Windows Azure cloud, where real-time and historical data are combined into view-anywhere dashboards that provide contextualized information on transfers, overall oil quality, and well productivity over time.
"Many flow devices and accessories are capable of looking at advanced signals, and identifying what's likely to affect measurements," adds Nathan Hedrick, product marketing manager for flow at Endress+Hauser. "These signals can get very granular and accessible. This means they can be watched second-by-second, and alerts set up for them to give users insights so they can make the right decisions sooner.
"Embedded intelligence isn't a substitute for human expertise. It's a complement to it. If an operator or engineer knows about a signal that's predictive for corrosion or build-up, such as oscillation damping or signal asymmetry in Coriolis meters, then they can establish setpoints or thresholds more proactively. Now, this can also be done in intelligent device displays or via their web servers, such as we have in flow components with our Heartbeat Technology package. It not only gives users access to signals, but it also indicates which are most pertinent to them. We advise that users looking to go in this direction take advantage of digital communication technologies. Otherwise, the wealth of information available from smart devices will be restricted by the number of analog signals."
Intelligence teaches new tricks
Just as flowmeters and transmitters have added data processing and networking for smarter and more sophisticated functions, many related components are following similar strategies. For instance, Alameda Hidroeléctrica Planta hydroelectric station in Malinalco, Mexico, needed a more reliable, cost-effective and accurate way to control water flowing to its turbines that generate up to 6 megawatts (MW), and recently implemented Rotork CK electric valve actuators for an economical, automated flow control solution. Their modular design enables operators to tailor CK specifications to precisely match the requirements of the application.
The actuators at the Alameda station also possess Centronik digital control units, which only need a main electrical supply to automate the formerly hand-operated valves. Centronik provides intelligent valve control with data logging for diagnostics and asset management. Rapid and secure commissioning and configuration are performed using Centronik's selector switches on its housing or by using a setting tool, and following user-friendly, menu-driven screens on its indication window, which normally displays valve position, valve status and alarms.
Smart future more connected
While most of the intelligence added to flow devices is still embedded at present, it's likely that more will be coming from networks and cloud services in the future.
"Similar to the Olympics motto—faster, higher, stronger—it's likely the only limit to the evolution of intelligence in measurement devices will be the imaginations of the developers," adds Krohne's Incontri. "Microsensors will also rapidly evolve and find a niche in process industries, and their combination with microprocessors will mean that processes will be better understood, more tightly and repeatably controlled, and more cost effective than ever before."