Case Study:
High-Signal Magmeter
Increases Production Rate

The largest single hydrocarbon deposit in the world is the Athabasca Oil Sands of northeastern Alberta, Canada. The site contains more than 1.7 trillion barrels of oil. Unlike a conventional oil reserve, oil sands (also called “tar sands”) contain oil in a sand or carbonate suspension with such high viscosity it is immobile under normal temperatures and pressures. Traditionally, the bitumen is removed by open pit mining, followed by transport and heating with solvents and separation of the oil and other products.

In recent years, efficiency at the Athabasca Oil Sands has been significantly improved by the adoption of Steam Assisted Gravity Drainage (SAGD), in which horizontal wells are drilled near the base of the bitumen deposit. Steam is injected into these wells, which heats the bitumen, reducing its viscosity and allowing it to flow under the force of gravity to the lower producer well. From there it is pumped to the surface, then on to the upgrader, which extracts the heavy oil for further refining. The most efficient means of moving the bitumen slurry to the upgrader is hydro-transport (i.e. pumping it with water). Since any water added for transport must be later removed, minimizing water improves efficiency and minimizes cost.

Accurate and reliable flow measurement of the bitumen slurry is complicated by the varying size of the sand — which can be as large as fist-sized rocks — and the uneven mixing and stratification of the heavy oil and water.

In the past, wedge meters were used to address this issue. Unfortunately, these meters suffer very high wear from the entrained rocks, impacting accuracy and requiring frequent rebuilds. Recently, however, users have started to adopt high-signal magnetic flowmeters for such applications.

Like any pulsed DC mag, a high-signal magmeter provides continuous automatic re-zeroing, for long-term stability and immunity to local magnetic fields and line voltage fluctuations. In addition, it contains heavy gauge windings, allowing it to operate with high coil current to generate a stronger signal, making it ideal for noisy flows. While many suppliers offer high-signal magmeters, the mags used in these applications operate at a coil current of five Amps — 10-20 times the current of traditional pulsed DC mags. In addition, the high-signal magmeters used in these applications use a special high-durability liner, designed in collaboration with oil sands producers for bitumen applications.

Not only does the true high-signal magmeter provide a more accurate, reliable signal and require less maintenance than the wedge meter, but it does not obstruct the flow. This allows an increase in flowrate, using the same pipe and pumps and with no increase in pumping cost. Since the production of most upgraders is limited by the bitumen input, this increase in flowrate directly increases plant production rate.

— Terry McLean
Measurement Specialist
Spartan Controls

Rising energy prices motivate users to better manage and minimize energy consumption. This article will focus on considerations — often overlooked — that can have a significant impact on measurements used in energy management. Users will learn how to: optimize gas and steam flow measurement repeatability through density compensation; minimize flowmeter permanent pressure loss; and optimize temperature measurement accuracy. Further, it will present methodologies that allow the user to quantify the impact of their existing practice and any ROI from adopting the recommended practice.

Best Practice #1:
Repeatability in Gas and Steam Flow Measurement
In almost every plant or mill much of the energy flows in the form of gas or steam and accurate and repeatable measurement of these flowrates is a prerequisite for optimizing and reducing energy consumption. Users measure natural gas flowrates to check gas billing into the plant and to optimize fuel-air ratio in combustion processes.1 For other gases, such as air and nitrogen, repeatable measurements help to optimize compressor efficiency.2 Steam flowrates are used in the “second element” of boiler feedwater control and help users improve efficiency of heat-transfer processes. Finally, with all of these fluids, users need to correctly allocate flows to internal plant users. Without repeatable measurements, it is impossible to evaluate the effectiveness of user initiatives for controlling energy usage, to identify areas for improvement, or to detect problems such as leaks.

What should users do to improve the accuracy and repeatability of their gas and steam flow measurements? Most users understand that they need to replace old, poorly maintained transmitters and damaged or worn primary flow elements such as orifice plates. Less well understood is the need for density compensation, yet its omission can cause very poor performance even in brand new, well-maintained installations.

In steam flow applications, the user is usually concerned with mass flow — evidenced by the use of mass units such as lb/hr or kg/s. With gases, users normalize their flowrates to standard conditions (i.e. SCFM, NCMH). These are also mass flow units, since the standard/normal conditions define fluid density. In many gas or steam flow applications, the user assumes that density is fixed and obtain mass flow by multiplying the fixed known density by the volumetric flowrate measured by, for example, the dp, vortex, ultrasonic, or turbine flowmeter. Unfortunately, density is never constant, not even in the simplest of applications.

Pressure variation in this application at a flowrate of 7,000 lb/hr is 2.5 psi, caused by pipe friction, regulator droop, and barometric variation.3 This 2.5 psi pressure variation causes a flow error of four percent, which is not repeatable. Because the relationship between pressure loss and flowrate is exponential, if flowrate is halved, the pressure drop will quarter; if it doubles, it will quadruple. As a result, the user can receive steam of widely varying density — and hence mass flowrate — on a minute-by-minute basis.

Temperature can also vary, even with saturated steam. As the steam flows, it loses pressure to friction, but — assuming the pipes are well insulated — cannot lose enthalpy. This means that it must gain superheat. Since the steam will have both a lower pressure and a higher temperature than expected, it will have a much lower density. For gases, temperature variation can be even more significant (e.g., source temperature variation; conductive losses/gains from poorly insulated pipe).

To eliminate the impact of these variations, the “best practice” for any gas or steam flow application is to continuously measure pressure and temperature and calculate density. Since no real gas is ideal, actual gas compressibility must be calculated using standards such as AGA-3, ISO5167 or steam tables.

Best Practice #2:
Minimize Flowmeter Permanent Pressure Loss
As the fluid enters the restriction, its pressure drops. This temporary pressure drop (DP=100 inH2O) is measured by the differential pressure transmitter and is related to the flowrate via Bernouilli’s Law of conservation of momentum.4

Once the fluid exits the restriction, some of this pressure is recovered — the unrecovered pressure is the permanent pressure loss. PPL for common industrial flowmeters can range from zero to greater than 20 psi.

In some applications, flowmeter PPL has no value. Obvious examples include flowmeters that are inline with mostly closed regulators or control valves. In the case of a mostly-closed control valve, if the PPL through the flowmeter is reduced, the additional fluid pressure will simply be scrubbed off in the valve. In the case of a regulator, if PPL is too high the flowmeter can simply be moved from a location downstream of the regulator to an upstream position.

Applications where PPL has value fall into three general categories:

1. Increase in fluid pressure and/or flowrate = increased production rate. In some cases, the fluid being measured is the product and an increase in flowrate will directly impact production rate (see “Case Study: High-Signal Magmeter Increases Production Rate”). Another example is in a batch-filling process, where an increase in flowrate allows the user to fill more quickly.
2. Flowmeter inline with a variable speed/frequency drive = reduced energy cost. As electricity rates have risen, users have increasingly replaced fixed-speed drives with variable speed drives. In a variable speed application, the drive provides only the energy necessary to provide the required flowrate. So, every watt of energy consumed in the line — including flowmeter PPL — must be made up by the drive. In this case, reducing the PPL in the flowmeter will provide direct energy savings.
3. New projects = reduce capital cost. If low-PPL flowmeters are specified during design, users can specify smaller motors and design their piping for lower pressure operation. A corollary is the case where the user has run out of pressure or flow — in this case, reducing flowmeter PPL may allow the user to avoid upgrades to their motors or boilers.

Once the user identifies applications where reducing flowmeter PPL can provide value, the next step is to quantify the value of the PPL in those applications. The user can then determine the ROI achievable by replacing the existing or proposed technology with low-PPL technology.

Quantifying Flowmeter Permanent Pressure Loss
The pressure loss through any flowmeter — or any restriction in the pipe — can be calculated using one of equations 1A-1C:5

1A. Liquid: PowerHP = (FlowrateGPM) x (PPLinH2O) / 38,000

1B. Gas: PowerHP = (FlowrateSCFH) x (PPLinH2O) x (ToF + 460)/ (Ppsia x 10.78 x 10)

1C. Steam: PowerHP = (Flowratelb/hr) x (PPLinH2O) / (rlb/ft3 x 305,000)

In many applications, the flowmeter is smaller than the pipe size. In these cases, the user must also include additional PPL through the pipe reduction and expansion, as well as any required upstream and downstream piping. The next step is to determine the dollar value of this pressure loss using equation 2, which assumes the user is pumping the fluid with a variable speed drive:

2. $/yr = PowerHP x (operating hours/yr) x ($/kwh)

Special attention should be paid to gas and steam flows with variable pressure. In most applications, demand for the gas or steam is based on mass flow. In other words, at a given production rate an application will require a certain NCMH of gas, or kg/s of steam. If inlet pressure is reduced, to obtain this required mass flow the volumetric flow must increase, increasing velocity and PPL. For example, if inlet pressure is halved, PPL will quadruple through the meter due to the squared relationship. While this may seem extreme, in many applications header pressure falls because demand — and flowrate — is high. To be safe, users should always calculate worst-case PPL at minimum line pressure and maximum mass flowrate.

Comparing Flow Technologies
In applications where the economic value of the average PPL is significant or the worst-case PPL frequently limits production rate, the user should consider replacing a high-PPL technology with a low-PPL technology. The actual PPL of a specific flowmeter in a specific application is normally determined using meter-specific software. For standard devices such as orifice plates, this software is available from suppliers and third parties. As described above, the user must usually add the pressure loss from any required line-size pipe reduction/expansion to the software’s calculated meter PPL.

This is not intended to be definitive — flow technologies are flexible — and allows the user to trade off PPL against turndown.6 For example, in a given application a two-inch Vortex flowmeter can provide much better accuracy over a much wider flow range when compared with a three-inch Vortex flowmeter. Similarly, an orifice plate with a lower beta ratio — a smaller bore — will maximize flow range, at the cost of a higher PPL.

Best Practice #3:
Optimize Temperature Accuracy by Sensor Matching
Many industrial applications that consume energy do so to maintain a process at a certain temperature. If that temperature is measured inaccurately, the process can be under- heated (or cooled), possibly impacting quality or safety; or over-heated (or cooled), wasting energy.

Resistance temperature detectors (RTDs) are often used in industrial applications that require high accuracy. RTDs rely on the principle that, for certain metals such as platinum, the resistance of the metal is linearly proportional to its temperature. Most users understand the need to compensate for resistance contributed by the lead wires – hence the widespread adoption of three-wire or four-wire RTDs. Less well understood is the need for “sensor matching”.

When an RTD is connected to a transmitter or DCS input, the user configures the transmitter to expect a certain sensor “type” — for example, “Platinum 100 ohm RTD.” The transmitter or DCS uses this to convert measured resistance to temperature, using the IEC-751 standard. Unfortunately, no real sensor provides this ideal performance in the real world, and in fact the IEC-751 standard includes a tolerance.

In applications where ignoring this “sensor interchangeability error” will reduce process safety or efficiency, the user needs to eliminate it by using “sensor matching.” To accomplish this, the supplier of the RTD provides “Calendar-Van Dusen” constants that define the “real-world” performance of a given individual sensor. These actual constants are then configured into the transmitter, eliminating the sensor interchangeability error and improving accuracy.

About the Author
Mark Menezes is measurement business manager for the Canadian territory of Emerson Process Management, Rosemount Division. Mr. Menezes has 14 years experience in industrial automation, a degree in Chemical Engineering from the University of Toronto, and a master’s of business administration from York University’s Schulich School of Business.


1. Menezes, “Calculating and Optimizing Repeatability of Natural Gas Flow Measurements,” Pipeline & Gas Journal, July 2001.
2. Menezes, “Improve Compressor Safety and Efficiency with the Right Pressure Transmitters,” Control Solutions, November 2001.
3. “Flow of Fluids through Valves, Fittings, and Pipe,” Crane Technical Paper 410, 25th Printing, 1991.
4. Miller, R.W., Flow Measurement Engineering Handbook, McGraw-Hill, Toronto, 1996.
5. “Dieterich Standard Energy Savings Planner,” Rosemount doc# DS-7105A.
6. Miller, R.W., Flow Measurement Engineering Handbook, McGraw-Hill, Toronto, 1996.