I wanted to highlight some of his thoughts from the whitepaper. Overall, it’s a very good overview of the flow measurement design process for custody transfer applications including all the components involved and how they fit together. If you’re new to one of the oil & gas upstream, midstream, or downstream business areas, this whitepaper is a great place to start.

He notes that the whitepaper was developed for the U.S. market and highlights some of the recommendations and/or standards provided by the American Gas Association (AGA) and American Petroleum Institute (API):

• AGA 3 – Orifice Metering of Natural Gas Part 2: Specification and Installation Requirements
• AGA 7 – Measurement of Natural Gas by Turbine Meter
• AGA 8 – Compressibility Factor of Natural Gas and Related Hydrocarbon Gases
• AGA 10 – Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases
• API 21.1 – Flow Measurement Using Electronic Metering Systems – Section 1: Electronic Gas Measurement

Jim cites the API 21.1 standard for the basic components of an electronic flow measurement system, which includes primary devices, secondary devices, and tertiary devices. Primary devices have direct contact with the fluids being measured. These include orifice, turbine, rotary, or diaphragm measurement.

A secondary device:

…provides data such as flowing static pressure, temperature flowing, differential pressure, relative density, and other variables that are appropriate for inputs into the tertiary device.

The tertiary device:

…is an electronic computer, programmed to correctly calculate flow within specific limits that receives information from the primary and/or secondary devices.

The selection of a primary device should be a function of the fluid being measured. In oil & gas production there may be a mixture of gases, liquids, sands, waxy paraffin, and other particulates, which Jim describes in industry vernacular as, “blood, guts, and feathers.” Orifice measurement generally handles these dirty gas measurements best. Turbine and positive displacement (PD) meters work better where there are little or no foreign matter particulates. Ultrasonic meters are well suited for large gas volumes with varying flow rates. I described how ultrasonic flow meter worked in a post, Ultrasonic Flow Measurement and Diagnostic Advancements. Coriolis flow and density measurement is another technology used, that I highlighted in a post, Custody Transfer Flow Measurement.

For secondary measurement, Jim cites the AGA-3 recommended practice. For orifice measurement, differential pressure, static pressure, and flowing temperature are measured. Static and differential pressures and temperatures are often measured with multivariable transmitters. For turbine and PD meters, only static pressure and flow temperature measurement is required.

For some applications, the quality of the gas measurement is important and requires a gas chromatograph (GC) as part of the secondary devices. Jim notes:

A GC will sample the natural gas being measured and feed back an analysis of the gas to the Tertiary Device or flow computer. The flow computer uses this analysis to determine the compressibility of the gas along with flow volume. The flow computer will take this data and with the use of a calculation from AGA 8 determine the compressibility of the gas under flowing conditions.

Tertiary devices include the flow computer, solar/battery systems for remote installations, antenna systems, radio systems, and SCADA systems. On the software side, historical data editing systems keep the historical flow data of the specific measurements dictated by API 21.1. This historical data provides the opportunity to recalculate flow volumes should there have been an error such as incorrect orifice size entered into the historical record.

There is much more than I can give justice to in this post, so I’ll refer you to the whitepaper for more on these systems and software, as well as site requirements for upstream, midstream, and downstream applications.

MP3 | iTunes

Download audio file (Electronic-Flow-Management-System-Design-Fundamentals.mp3)

Related Posts:

• Custody Transfer Flow Measurement
• Coriolis Flow Measurement to Natural Gas Accounting
• Integrating Gas Chromatographs with Control and Device Management

Industry-first measurement validation diagnostic on Rosemount temp transmitter #PAuto #Safety http://t.co/GvPN26j9

The link goes to Eoin’s Read-out Instrumentation Signpost blog, where he shares how the new measurement validation diagnostic in Rosemount 848T fieldbus temperature transmitters help to address some of the issues with thermocouple and RTD temperature measurement:

Temperature sensors, such as thermocouples and RTDs (resistance-temperature detector), can degrade over time due to harsh process conditions, vibration, and other factors.

I connected with Emerson’s Ryan Leino, a member of the Rosemount Temperature team, who shared some information on how the measurement validation diagnostic works. It provides validation of measurement data which can help identify the following issues:

• On-scale Errors- when the output of a transmitter is within process alarm limits yet does not accurately indicate actual process information
• Invalid measurement readings that lay outside of alarm limits when actual process variable is within acceptable range
• Abnormally fast process rates of change

These issues are often due to failing sensors (most common), electronic interference, corroded termination points, loose electrical connections, high vibration and runaway reactions. These conditions can lead to unnecessary shutdowns, inefficient energy usage, off-spec product, lower yields and unsafe process conditions. The measurement validation diagnostic can detect these measurement abnormalities and help plant staff take preventive action before they become a major issue, saving time and money associated with process shutdowns and helping processes run more efficiently.

As a temperature sensor starts to degrade, its signal noise will increase resulting in unreliable readings. Measurement Validation works by monitoring the signal noise and using it to calculate a deviation value indicating the magnitude of this noise. This calculated deviation value is then compared to a user selectable limit, which, if exceeded, can alert plant staff of an unreliable measurement point and possible sensor degradation.

Ryan and team have put together a measurement validation website that shares more on what the measurement validation diagnostic is and how it works, which includes several informational videos and a 3-D interactive product model.

MP3 | iTunes

Download audio file (Temperature-Transmitter-Measurement-Validation-Diagnostic.mp3)

Related Posts:

• Temperature Measurement and Installation Practices
• Thermocouples or Temperature Transmitters in Safety Systems?
• Wireless versus Fieldbus Cost Comparison

This is a flow control station for a copper slurry pipeline in the Andes mountains.

In a slurry-type mining application, the ore is ground up into fine particles and mixed with water, so that the mixture can now be pumped through a pipeline under high pressure. The mixture of solids and water has the consistency of soft ice cream but it is extremely abrasive. Rotary vane actuators are well suited for this type of application.

The flow control station is automated with rotary vane actuators.

The large pumps that generate flow and pressure in the pipeline also produce a considerable amount of vibration. In and around pumping stations, this high vibration is transmitted up through the valves and into the actuators causing long-term damage to any component in a cantilever-type orientation. The rotary vane actuator is compact and fits concentrically around the valve’s flange with its center of gravity directly over the valve stem. With its simple geometry, the rotary vane actuator has proven to withstand the high vibration over tens of years of operation. Actuator control cabinets are typically mounted beside the pipeline where they are not subjected to the vibration propagating through the pipeline.

Rotary valve actuators inside a slurry pumping station.

Unlike gas and oil pipelines, a slurry pipeline contains solid ore material. The slurry causes the valve’s torque requirements to remain relatively constant throughout the complete 90º rotation of the ball valve, in other words, break torque and run torque are nearly the same. The torque output of a rotary vane actuator coincides with the valve’s torque requirement because the output torque of this actuator remains constant throughout the 90º stroke.

Control enclosures are off-mounted due to excessive vibration.

Controlling the flow velocity in a slurry pipeline is critical to its operation. If the slurry is moving too slow, the solid material can separate from the liquid and literally clog the pipeline like a stopped up drain. On the other hand, if the slurry is flowing too fast, the abrasive material can destroy the pipeline from the inside out. One of the pictures is of a pipeline choke station designed to control slurry that is flowing too fast. What this means for the actuator is that it requires very precise speed control. Typically, the actuators are large, require very high flow hydraulic controls, and are on spool-type control valves that become a constant drain on the hydraulic power supply accumulators.

The Shafer rotary vane actuator includes custom-engineered high flow hydraulic controls of the poppet valve design for positive bubble tight shutoff with no control leakage.

MP3 | iTunes

Download audio file (Rotary-Vane-Actuators-in-Slurry-Mining-Applications.mp3)

Related Posts:

• Identifying Pneumatic Energy Savings with the Energy Responsible Tool

Remarkably – and almost abruptly – it now appears that the enormous challenge of satisfying a doubling in world energy demand by 2050 will probably be met. But it won’t be through renewable energy sources like solar and wind, although the role of these renewables will indeed rise. The lion’s share of the new energy production will come instead from shale oil and shale gas, deepwater drilling, oil sands and other unconventional sources of fossil fuel.

Alan highlights the role new technologies have played:

Behind these tectonic shifts are new technologies, some of which have quickly become well-known. They include hydraulic fracturing (“fracking”) and horizontal drilling, in the case of shale gas and shale oil, and steam assisted gravity drainage (SAGD), in the case of oil sands.

These technologies are:

…converting abundant coal to produce essential chemicals that previously were made only from petroleum. They’re re-engineering power plants that support major industrial facilities to use renewable fuels like wood waste and food byproducts. And they’re minimizing energy loss in production processes.

In posts such as Impact of Shale Gas on Coal Conversion Technologies and Biomass Fuel in Alternative Energy Production, Alan describes these technologies in greater depth.

Advancing technologies open up opportunities for cleaner fuels. He describes two conversion processes:

With GTL [gas to liquid] or CTL [coal to liquid] technology, we can also capture impurities like sulfur, nitrogen oxides, mercury, and soot in the production process – thereby creating a cleaner-burning fuel.

Driving some of these trends is the current economics among alternative sources of energy:

The combination of expensive oil and complex technologies have thus brought us into the age of “the fungible BTU,” in which we have unprecedented flexibility to choose among feedstocks.

Technologies that can control based on the energy or BTU content provide the opportunity for:

…a “hybrid” powerhouse that can seamlessly juggle among these renewable and conventional fuels. The results include reduced consumption of fossil fuels, reduced greenhouse emissions, and lower costs.

Give the article a read to see how technologies combined with vision and action are helping global energy supply respond to increasing demand, and do it with greater efficiency.

Related Posts:

• Plentiful Natural Gas—Impact on US Process Manufacturing
• Is Natural Gas the New Alternative Energy Source?
• More Efficient, Wood-Based Biomass Energy Production

I received a note from Craig Truempi with Emerson local business partner, Novaspect. He shared:

This fan bearing failed last week, and as you will see the red line (PeakVue) clearly identifies the fault, while the blue line (Overall Vibration) once again missed it.

This is a great example that demonstrates a perfect fit for wireless machinery monitoring using PeakVue with the CSI 9420 Wireless Vibration Transmitter.

I asked Craig and our Asset Optimization team to give me some more background to share with you. They noted:

Not all vibration and preventive maintenance can be solved by using a route-based CSI 2130 Machinery Health Analyzer and specifically with overall vibration monitoring. In this case, the process manufacturer was using a CSI 9420 to provide continuous monitoring of the fan. With the early warning provided by PeakVue measurements, they were able to shut down the fan prior to complete failure. When the fan was being repaired, the bearings were inspected and it was clear to see the bearings had failed.

Without PeakVue and the CSI 9420, this bearing defect could have continued to deteriorate and ultimately lead to a more costly failure and extended downtime.

The advancement of technology through high-speed digital sampling has improved everything from the movies and music we enjoy to the early warning provided to maintenance teams in manufacturing plants.

MP3 | iTunes

Download audio file (Spotting-Bearing-Failure-in-Time-before-Complete-Fan-Failure.mp3)

Related Posts:

• Accessible Wireless Vibration Monitoring
• The Peaks Provide the Early Warning in Machinery Protection
• If it Moves—Monitor it!