Level Instrumentation for Steam Generation Process Applications

Steam is today’s utility player in the industrial energy arena. It cleans and sterilizes, dries and concentrates, separates and evaporates. In cookery, it preserves flavor, texture, and retains nutrients. In chemistry, it fosters reactions by controlling process pressure and temperature. In biotechnology, it’s essential for growing production organisms. Steam ranges in purity from boiler grade for routine tasks, to culinary grade “clean steam” for food and dairy, and graduates up to super pure, pyrogen-free steam for biopharmaceutical use.

Generated steam is ubiquitous because it’s industry-friendly. It’s intrinsically safe, flexible, economical, aseptic, and environmentally benign. Steam can arise from fossil fuels, biomass or biogas. Its high efficiency is due to its ability to return a significant portion of condensate to the generation cycle. With proper maintenance, a steam plant can last for decades.

Magnetrol® has produced a special applications brochure on level instrumentation for the steam generation process. This brochure focuses on the industrial steam boiler. If you are interested in steam applications for power generation, the massive electricity-generating utility boilers are addressed in our Power Gen and Nuclear brochures. This blog post, the first in a three-part series, will discuss three aspects of the steam loop: make-up water treatment, feed water deaeration, and boiler feed water treatment. Future posts in the series will cover the rest of the steam loop as well as flow control applications.

STEAM LOOP: 1. Make-Up Water Treatment
It all begins with water, the essential medium for the steam generation process. Conditioning water properly can increase boiler efficiency and extend the boiler’s operating life. Improper or nonexistent feed water treatment is the major cause of boiler failure.

All natural sources of fresh water require varying degrees of treatment prior to boiler use. Boiler feed water treatment prevents scale and deposits, removes dissolved gases, protects against corrosion, eliminates water and steam carry-over, and optimizes boiler efficiency and minimizes maintenance costs.
Feed water is treated and conditioned in three phases:
1. Raw make-up water is treated before entering the deaerator
2. Treated make-up water and return condensate merge in the deaerator for removal of dissolved gases
3. De-oxygenated and heated feed water enters the boiler where it is further treated with chemicals

Feed water treatment requirements vary greatly. In rare cases, raw make-up water only needs filtering. More commonly, some form of external treatment is needed, as in the typical process units listed below.

Raw water with sediments may require a settling tank with the addition of chemicals to foster precipitation of the suspended matter. Clarified water is then drawn off at a surface outlet.
Continuous Level: Eclipse® 706 Guided Wave Radar (GWR); Echotel® Model 355 Non- Contact Ultrasonic Transmitter

Coarse and Fine Filtration
Suspended solid impurities are reduced or eliminated by passing make-up water through a filter. If the suspended solids are very fine, a flocculation step may be required.
Continuous Level: ECHOTEL Model 355 Non-Contact Ultrasonic Transmitter; Pulsar® R95 Thru-Air Radar Transmitter; Model R82 Thru-air Radar Transmitter

Water Softening
Calcium and magnesium are hard scale forming minerals that build up on boilers and steam-related equipment resulting in costly repairs, increased energy consumption, and plugged equipment. Softening occurs as hardness minerals attach to the softening resin and “exchange” for sodium.
Continuous Level: PULSAR R95 Thru-Air Radar Transmitter; ECLIPSE 706 Guided Wave Radar; Atlas™ or Aurora® Magnetic Level Indicators (MLIs).

Demineralization is typically an ion exchange process whereby minerals or mineral salts are removed from water. Chemical treatment or a feed water evaporator can be used as alternative methods, the latter using extraction steam to remove impurities in raw water.
Point Level: ECHOTEL 961 Ultrasonic Level Switch; Model T20 Single Stage Float Level Switch.
Continuous Level: ECLIPSE 706 GWR; Digital E3 Modulevel® Displacer Transmitter. Point Level: Models T5x and T6x Float-Based Level Switches.

Header Tank
The treated make-up water is routed for storage in a cold-water header tank. From there the water passes on demand through a flash tank for heating and on to the deaerator for degassing.
Continuous Level: Model R82 Non-contact Radar Transmitter; ECLIPSE 706 GWR; PULSAR R95 Thru-Air Radar Transmitter.

STEAM LOOP: 2. Feed Water Deaeration
Because boiler and steam systems are made primarily of steel and the heat transfer medium is water, the potential for corrosion is very high. Dissolved oxygen is the major cause of boiler system corrosion. Oxygen and other gases are removed from both feed water streams—treated make-up water and return condensate feed water—when they merge in the deaerator. Deaerators remove non-condensable gases from feed water streams by steam heating and by aggressively agitating incoming water. The deaerator’s storage section is typically designed to hold enough water for ten minutes of boiler operation at full load.


Level control on a deaerator typically measures the level in the storage tank and modulates a control valve on feed water streams to maintain tank level at the desired set points.
Continuous Level: ECLIPSE 706 Guided Wave Radar; ATLAS or AURORA Magnetic Level Indicators.
Point Level: Series 3 ASME B31.1 External Caged Liquid Level Switch.

STEAM LOOP: 3. Boiler Feed Water Treatment
For higher boiler efficiencies, the feed water is further conditioned prior to and upon entering the boiler. First, the water is preheated by an economizer using the boiler’s hot exhaust gas streams. Next, water treatment inside the boiler reduces foaming, eliminates adherence of suspended matter to boiler internals, further prevents corrosion and scaling by eliminating residual oxygen. Chemical feed systems are employed for both internal boiler treatment and in the make-up water treatment unit.


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Understanding Tank Bridle Level Measurement

A bridle is a vertical pipe connected to the side of a storage tank or process vessel, typically with side/side or side/bottom connections. Because the fluid inside the bridle will rise and fall equally with the level of fluid inside the tank or vessel, the bridle has been adapted for
level measurement on a broad scale.

The Magnetrol® use of the term “bridle” refers to a bypass chamber on a larger process vessel on which the level instrumentation for that vessel is mounted. Bridles usually do not have level equipment extending into the bridle itself. Level equipment is typically placed in its own cage or nozzle attached to the bridle.

Bridle Advantages

 Tank bridle level measurement has provided industrial users with distinct advantages:

Isolation: Because a level instrument mounted in a bridle is isolated from the process it can be calibrated or maintained without disturbing the process.

Fewer Connections: A bridle reduces the number of connections necessary on the process vessel. This is especially important on boiler code vessels that require qualified welders and procedures.

Prudent Design: Level instrumentation is often the last consideration on a project. Mounting the instrumentation on a bridle eliminates the need for planning multiple instrumentation connections on the vessel.

Saves Time: Because instrumentation is typically left until the end, ordering a bridle with all the level instrumentation cuts down on the time necessary to add connections and install the instrumentation at the project deadline.

Avoids Obstructions: When a tank has mixers, agitators, aerators, ladders, or structural bracing, a bridle avoids any interference between these objects and the level controls.

Reduces Turbulence, Foam: In a highly agitated vessel, a bridle calms the surface to be measured and reduces foam to improve measurement accuracy.

Isolation: Because a level instrument mounted in a bridle is isolated from the process it can be calibrated or maintained without disturbing the process.

Bridle Instrumentation

Here are a few of the most common level instrument technologies used for tank bridle measurement:

Guided Wave Radar GWR mounted in a cage is well suited for bridle measurement. Configuration is fast, no calibration is required, and accuracy isn’t affected by changing densities, dielectrics, high temperatures or high pressures. MAGNETROL Eclipse®  transmitters are available with a wide range of probes, materials and options.

Magnetic Level Indicators Developed for the most demanding industrial applications, MLIs provide local visual indication and remote indication when combined with a transmitter. Highly visible flags magnetically coupled to the moving float provide local level indication. Aurora® (float and GWR transmitter redundancy) and Atlas™ (float-based MLI) can be customized for unique application solutions.

Magnetostrictive Transmitters Designed to attach quickly and easily to magnetic level indicators, magnetostrictive transmitters offer high accuracy and high linearity when combined with MLIs. The MAGNETROL Jupiter® magnetostrictive transmitter is available with an innovative dual compartment design.

External Cage Float Switches A wide range of float switches suitable for bridle applications with flanged and sealed cage designs include ASME B31.1 construction for boiler and power plant use and B31.3 construction for petrochemical use. HP and HT versions and a selection of switch styles and material options are available.

Displacer Controllers Displacer Controllers utilize simple buoyancy principles to detect and convert liquid level changes into a stable output signal. Modern displacer controllers serve most liquid level measurement and control applications including those with varying dielectric, vapors, turbulence, foam, buildup, bubbling or boiling and high fill/empty rates. The MAGNETROL Digital E3 Modulevel® is an advanced, intrinsically safe, two-wire controller that comes in a variety of configurations and pressure ratings for varied applications.

Ultrasonic Contact Point Sensors Nozzle-mounted ultrasonic switches are mounted horizontally on bridles for high or low level alarm applications. The MAGNETROL Echotel® Model 961 Level Switch offers advanced transducer designs, extensive hazardous location approvals, and self-test technology. Pulsed signal technology for superior performance in difficult conditions and excellent immunity from electrical noise interference are also featured.

Thermal Dispersion Point Sensors Nozzle-mounted thermal dispersion switches provide a high level of performance for level and interface applications on bridles. MAGNETROL Thermatel® Model TD1/TD2 switches feature continuous diagnostics with fault indication, temperature compensation, narrow hysteresis, and fast response time.

MAGNETROL has created a pamphlet on tank bridle level measurement that provides even more information about bridle instrumentation, specification, and torque tube replacement. Download the pamphlet today to learn more.


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Guided Wave Radar Instrumentation in Steam Drum and Feedwater Heater Applications

With the addition of non-conventional, renewable generation to the energy mix, many operators have questions and concerns about level technology and how it can improve the efficiency of their power plants. Magnetrol® expert Donald Hite recently answered questions about guided wave radar level control instrumentation as part of a power Optimizing Level Control Webcastindustry-focused webinar, “Optimizing Level Control to Meet New Generation Demands.” This week’s blog post shares some of that Q&A.

Question: What is the standard mounting for a guided wave radar instrument in a feedwater heater and in a steam drum? Should the instruments be mounted externally or internally?

Answer: The standard mounting for both a feedwater heater and a steam drum is an external chamber. Level instrumentation on feedwater heaters are never directly inserted – the internal construction of a heater prevents top entry of level sensing devices; thus, limiting them to external mount only. Historically, guided wave radar is also mounted externally on a steam drum. However, recent research and testing has explored the possibility of internal installation. MAGNETROL has proven that direct insertion of guided wave radar into a steam drum is not only a viable, but also a more effective and less complicated method of measuring the level. As of right now, all of our direct insertion GWR installations in steam drums are being done internationally due to the fact all of the R&D and testing was accomplished in that market space. On the domestic front, direct insertion is a new concept and will catch on as plants are made aware of the cost and performance benefits, which I should say are significant.

Question: One of the claims made about guided wave radar is that it requires no external input to achieve and maintain accuracy. What does this mean?

Answer: The fundamental principle of Guided Wave Radar technology does not rely on specific gravity or inference as the basis for the measurement. Consequently, parameters which normally affect such devices have relatively little impact on the measurement. It doesn’t require any external input to compensate for process conditions that affect the specific gravity of the material being measured. This is in contrast to how many other level instruments function. Take a displacer, for instance. A displacer is designed to be most accurate at the specific gravity of the material being measured at operational conditions. Any fluctuations from the design criteria relative to specific gravity have a negative impact on the accuracy. A similar statement can be made about differential pressure technology. These vulnerabilities, if uncorrected, reduce accuracy during critical startup and cycling conditions where swings in specific gravity are commonplace. Guided wave radar gets its return signal from the surface of the material being measured. As a consequence, its accuracy is not contingent on correcting for fluctuations in specific gravity. The key is ensuring the material being measured is of sufficient dielectric value during all application conditions to return a signal that can be tracked.   Although the saturated steam in the vapor space does affect the propagation speed of microwave energy, the correction is self contained and accomplished internally in the unit, completely transparent to the end user. When you use guided wave radar in any given steam application, you no longer need to introduce other measurements, which could be sources of additional error, to determine the true level.

Question: How does guided wave radar work with foaming applications?

Answer: There are essentially three scenarios when using guided wave radar on foaming applications. In the worst case scenario, the foam absorbs all of the microwave energy eliminating GWR as a level solution. Although rare, it does occur from time to time. Another possibility is that it has no impact at all. The microwave energy passes through the foam unchallenged and the level is easily acquired. In a third scenario, the foam is of sufficient dielectric value to create a reflection which can be tracked as level while low enough to allow the energy to pass through creating a second reflection from the actual liquid surface. In this scenario the instrument can be configured to track either the foam or liquid level.

Question: Is guided wave radar now the industry’s preferred option for drum level control?

Answer: At the moment, it is not. The most common technologies you see used on drum level applications are differential pressure and conductivity. Up until recently, the process isolation seal material used in GWR probes for saturated steam applications could not tolerate the temperature common on high-pressure drums. GWR has always been a viable level solution on the LP and IP drums. Most customers prefer to standardize on a single technology for all drums. Since GWR could not handle the HP drum it did not see much service for this reason.

To learn more about guided wave radar technology and optimized level control in steam drum and feedwater heater applications, view the webcast “Optimizing Level Control to Meet New Generation Demands.”

Heat Rate Webcast

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Orion Instruments® Acquires ASME U Stamp Certification

Orion Instruments® was recently certified as an ASME Section VIII, Division 1 Boiler and Pressure Vessel Code facility. This achievement verifies that ORION’s engineering, manufacturing, and quality systems meet the stringent requirements of ASME Sec. VIII, Div. 1. As a result, our capabilities now include the construction of code stamped chambers to meet end user specifications.

Adding ASME Sec. VIII, Div. 1 certification to our construction code offerings gives ORION the ability to offer custom engineering, design, and manufacturing at any level the process application may require. Customers can be assured that their magnetic level indicators (MLIs) are manufactured with the highest quality and craftsmanship regardless of construction code.

There are a limited number of MLI manufacturers with ASME Sec. VIII, Div. 1 certification.

This certification allows ORION Instruments to provide the following:

  • ASME Sec. VIII, Div. 1 U stamp (full implementation of code with stamp, National Board Registration, 3rd party inspection, and supporting documentation)
  • Construction in accordance with ASME Sec. VIII, Div. 1
  • Designed to code calculations
  • Documentation to customers’ specifications
  • No 3rd party inspection
  • No National Board registration
  • No “U” stamp designator
  • Construction in an ASME Sec. VIII, Div. 1 certified facility
  • Ensures the highest level of quality and manufacturing processes

For more information on ASME Boiler and Pressure Vessel Code (BPVC) Section VIII, Division 1, or to acquire a copy of the certification, please contact the ORION Instruments factory or visit our website.

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Technologies for Liquid Interface Level Measurement

The need for interface level measurement arises whenever immiscible liquids–those incapable of mixing—reside within the same vessel. The lighter material rises to the top and the heavier material settles at the bottom. In oil production, for example, water or steam is used to extract oil from a well. Well fluids then route to production separators where they settle into their primary constituent parts as a water-hydrocarbon interface. Water may also be used as a transport medium or a cleaning agent and forms an interface with an allied material which is later extracted.

Interfaces are most commonly found in the diverse separation processes that are essential to every industry. Separation recovers additives, catalysts or solvents, extracts impurities, and routes media into different processing channels.

Principal Interface Applications

Here are a few of the most common industries and processes where interfaces are found:

Petroleum and Gas

  • Separators
    • LPG Dehydrators
    • Heater Treaters
    • Crude Desalters
    • Free-water Knock-out
  • Regenerators
    • Coalescers
    • Crude Dewatering
    • Acid Settling Tanks
    • Alkylation Tanks
    • Coking Drums

Water & Wastewater

  • Settlement Tanks
    • Clarifiers
    • Sludge Thickeners
    • Filtration Systems
    • Final Effluent Monitoring

Other Industrial

  • Liquid Oxygen and Nitrogen production
  • Digester Vessels
  • Extractors & Separators
  • Grease Traps
  • Pulp and Paper
  • Mining and Quarrying
  • Food and Beverage
  • BioPharmaceutical
  • Chemical Plants
  • Storage Facilities

Though our emphasis is on liquid/liquid interface, interfaces also form between liquid and solids, liquid and foam, or liquid and a gas—such as gases (other than air) that are used in tank blanketing.


Immiscible liquids meet along an interface layer where they undergo some amount of emulsification. This emulsion layer (also called a rag layer) may form a narrow and precise boundary; but more frequently it is a broader gradient of mixed liquids—or liquids mixed with particles that form a slurry. Generally, the thicker the emulsion layer, the greater will be the measurement challenge. Knowing the position of a process interface is necessary for maintaining product quality and operations efficiency. The interface is measured and controlled by precision level switches and transmitters. Though at least 20 different types of liquid level measurement devices are in service today, only a very few are suitable for accurate and reliable interface level measurement.

Level Measurement Technologies

Here are three of the most reliable technologies for interface level measurementThe information presented describes the technologies as they pertain to Magnetrol® level instrumentation:

Displacer Controllers and Transmitters- Modulevel®
Measurement Principle: Movement of the interface level along the length of the displacer causes the precision range spring to extend or compress. This causes the movement of the core within a linear variable differential transformer in the Digital E3 Electronic MODULEVEL resulting in a digital or analog output. In the Pneumatic MODULEVEL, this causes the movement of a magnetic ball which guides the magnet carriage resulting in a pneumatic output change.
Interface Measurement: This technology is widely used for interface service because it is unaffected by emulsions and will accurately track the middle of the emulsion layer.

Thermal Dispersion- Thermatel®
Measurement Principle: Switches using thermal dispersion technology detect heat transfer which reduces the temperature difference between the switch’s two sensors; one sensor is for reference and the other is heated to a temperature above the process temperature. The temperature difference is greatest in air, then decreases when cooling occurs due to a change in media. The electronics compare the electrical signal from the sensor against the set point and provide a relay actuation.
Interface Measurement: The THERMATEL TD1/TD2 and TG1 switches have been designed and engineered for level, flow or interface detection. When used as an interface detection switch, the set point can be adjusted to detect the difference in media between two fluids that have different thermal conductivity. Water has a very high thermal conductivity while organic materials (oil) have a much lower thermal conductivity. THERMATEL detects the difference in media due to the temperature difference which will be greater in the organic layer than in the oil layer.

Guided Wave Radar- Eclipse®
Measurement Principle: ECLIPSE is based on Time Domain Reflectometry. TDR transmits pulses of electromagnetic energy down the wave guide, or probe. When a pulse reaches a liquid surface that has a higher dielectric constant than the air in which it is traveling (dielectric constant of 1), the pulse is reflected. Ultra high-speed timing circuitry provides an accurate measure of liquid level. Even after the pulse is reflected from the upper surface, some of the energy continues along the length of the probe through the upper liquid. The pulse is again reflected when it reaches the higher dielectric lower liquid.
Interface Measurement: The dielectric constant (ε) of the interface media is critically important for GWR. As shown in the illustration at right, the upper dielectric should be between 1.4 and 5, and the lower dielectric should be greater than 15. The typical oil and water interface application shows the upper, nonconductive oil layer being 2, and the lower, very conductive water layer being 80. ECLIPSE measurement is suitable where the interface is clean and distinct and the depth of the emulsion layer is shallow.

MAGNETROL has produced a special applications brochure featuring these and more interface level measurement technologies, with an overview of technology specs, process capabilities, and transmitter options. Download the brochure today and learn more about the benefits and applications of each technology.


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Level and Flow Solutions for Natural Gas Compression

From natural gas extraction to pipeline transmission, compressors are an essential technology employed throughout production and distribution chains to increase the pressure of natural gas by reducing its volume. At the wellhead, compression allows a low- pressure well to produce higher volumes of natural gas—in some instances, well production may be entirely dependent upon gas compression. In natural gas processing plants, intermediate and end product gases are compressed to facilitate gathering and processing operations. In pipeline transport of purified natural gas, compression stations ensure the movement of gas from the production site to the consumer. Compressors may also be used in association with above ground or underground natural gas storage facilities.

This blog post explores level and flow solutions for some common technologies used in natural gas compression. If you missed the previous posts in our series on the natural gas processing industry, you can find them here, from July 14 and July 21.


Lubrication systems protect compressor components from increased amounts of wear and natural_gas_compression_1deposit formation and help the equipment run cooler and more efficiently. A wide range of engine lubricants formulated with different base oils are available. Lubricants vary by ISO grade, viscosity, flash point, and formulation. Lubricating fluids are typically stored in integral stainless steel and carbon steel tanks and in remote bulk storage tanks that are monitored for level.
Challenges: Level monitoring of lubricant reservoirs will ensure the proper functioning of compressors. Temperature shifts in integral reservoirs affect media density that will exclude some level technologies, such as pressure transmitters. Because ISO cleanliness levels increase lube change frequency, controls should be easy to remove.
Level Instrumentation:
Point Level: Echotel® Model 961 Ultrasonic Gap Switch; Thermatel® Model TD1/TD2 Switch; or Tuffy® II Float-actuated Switch
Continuous Level: Eclipse® Model 706 Guided Wave Radar Transmitter; or Jupiter® Magnetostrictive Transmitter
Visual Indication: Atlas™ or Aurora® Magnetic Level Indicators


Natural gas can travel through thousands of miles of pipeline. Compressors placed at key intervals keep the natural gas moving evenly and reliably. A typical compressor station consists of an inlet scrubber to collect liquids and slugs that may have formed in the gas pipeline. The scrubber consists of a primary section where liquids and solid parts are natural_gas_compression_2separated from the gas stream and a secondary section where oil mist is removed.
Challenges: The liquids collected from the suction scrubber are typically routed by way of scrubber level control valves to a low pressure (LP) tank. The vapors produced from the flashing liquids are vented to the atmosphere or to a flare. The low pressure condensate is periodically trucked out. Scrubbers are often equipped with high and low level alarms.
Level Instrumentation:
Point Level: ECHOTEL Model 961 Ultrasonic Gap Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators


Compression station scrubbers and filters that capture liquid waste and unwanted particles route waste liquids to a storage tank. Wastes can be water condensates or heavier hydrocarbons from the natural gas. The wastes are collected in one or several tanks natural_gas_compression_3depending on the size of the remote station. As a waste tank fills, tank trucks are typically scheduled for tank emptying operations. As these wastes are hazardous materials, the waste holding tanks are classified as Class 1, Div. 1 areas.
Challenges: Measurements for both total level and interface levels between the condensed hydrocarbons and condensed water are typically made. Tank level monitoring can be provided with overflow control and alarm systems or shutdown pumps when level falls below the specified low level.
Level Instrumentation:
Point Level:
ECHOTEL Model 961 Ultrasonic Gap Switch; or THERMATEL Model TD1/TD2 Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter; or JUPITER Magnetostrictive Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators


Liquid in the vent stream can extinguish the flame or cause irregular combustion and smoking. In addition, flaring liquids can generate a spray of burning chemicals—a “rain of fire”—that create a severe safety hazard. A knockout drum collects these liquids prior to entering the flare system. A level gauge and drain connections are built into the knockout natural_gas_compression_4drum.
Challenges: When a large liquid storage vessel is required and the vapor flow is high, a horizontal drum is usually more economical. Vertical separators are used when there is small liquid load, limited plot space, or where ease of level control is desired. Knockout drums are equipped with instrumentation to monitor liquid level with pump out or drain facilities. High and low level alarms are frequently installed in knockout drums.
Level Instrumentation:
Point Level: ECHOTEL Model 961 Ultrasonic Gap Switch; or External Cage Float Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter; or E3 MODULEVEL Displacer Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators


natural_gas_compression_5From the wellhead to the compression station, monitoring the flow of natural gas is essential. Other flow monitoring applications found in natural gas settings may include mass air and compressed air flow, process and waste gas flow (often required for reporting environmental emissions), and pump protection afforded by the sensing of reduced or no-flow conditions.
Challenges: Significant flow variables include pipe diameters, wide flow ranges, varying velocities, and low flow sensitivity. Flow meters ensure efficient operation at rated SCUM output and also detect leaks. A flow meter with a totalizer provides an accurate measurement of air or gas consumption. A flow switch along a pump’s discharge piping will actuate an alarm and shut down the pump when liquid flow drops below the minimum flow rate.
Level Instrumentation:
Flow Alarm:
THERMATEL Model TD1/TD2 Thermal Dispersion Flow Switch
Pump Protection: THERMATEL Model TD1/TD2 Thermal Dispersion Flow Switch
Continuous Flow: THERMATEL Model TA2 Thermal Dispersion Mass Flow Meter

Natural Gas Processing

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Level Instrumentation for the Natural Gas Industry

The natural gas industry relies on high-quality, dependable level instrumentation to ensure efficiency and safety. Processes like recovery and storage require innovative level and flow solutions. This blog post discusses level control for natural gas industry applications. This is the second in a series on Magnetrol® offerings for natural gas processing. Be sure to catch up on the first post, from July 14.

Separating the hydrocarbons and fluids from pure natural gas produces pipeline quality natural_gas_industry_!dry natural gas. The two principle techniques for removing Natural Gas Liquids (NGLs) are the absorption and the cryogenic expander method. The absorption method is very similar to that of dehydration except that an absorbing oil is used instead of glycol. Once NGLs have been removed from the natural gas stream, they must be separated out, or fractionated.
Challenges: Absorption method level control is typically found on flash drums, separation towers and reflux systems. Cryogenic method level control is applied to the separator and dehydrator.
Level Instrumentation:
Point Level: Echotel® Model 961 Ultrasonic Gap Switch; or Thermatel® Model TD1/TD2 Thermal Dispersion Switch
Continuous Level: Eclipse® Model 706 Guided Wave Radar Transmitter; or E3 Modulevel® Displacer Transmitter
Visual Indication: Atlas™ or Aurora® Magnetic Level Indicators

A Vapor Recovery Unit (VRU) captures valuable volatile organic compounds and other rich gas streams that may otherwise be a significant environmental pollutant. A Vapor Recovery Unit (VRU) collects from storage and loading facilities, reliquefies the vapors, natural_gas_industry_2and returns the liquid hydrocarbons back to storage. Methods to recover vapors include absorption, condensation, adsorption and simple cooling.
Challenges: A VRU is a simple, economical process unit that provides EPA compliance and improves operating economies by capturing up to 95% of fugitive emissions. Critical to the VRU is the flash drum where vapors are reliquefied. Liquid level control of the flash drum is essential.
Level Instrumentation:
Point Level: Series 3 External Cage Level Switch; Tuffy® II Float-actuated Switch; ECHOTEL Model 961 Ultrasonic Gap Switch; or THERMATEL TD1/TD2 Thermal Dispersion Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter; or E3 MODULEVEL Displacer Transmitter

Natural gas, oil, liquid fuel, treatment chemicals, extracted condensate from separators and water are stored in gas fields. Unlike midstream tank farms at terminals and refineries, field storage consists of smaller vessels. Diesel generator fuel, potable water, and fire water are also stored in tanks.
natural_gas_industry_3Challenges: Tank level monitoring can be provided with overflow control and alarm systems or shutdown pumps when level falls below the specified low level. Interface controls will sense the beginning of an oil/water interface during tank dewatering and control the water draw-off.
Level Instrumentation:
Point Level:
Model A15 Series Level Switch with optional Proofer®; or ECHOTEL Model 961 Ultrasonic Gap Switch
Continuous Level: ECLIPSE Model 706 Transmitter; Pulsar® Model RX5 Radar Transmitter; or Jupiter® Magnetostrictive Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators

Produced water, wash-down water or collected rainwater require treatment whether natural_gas_industry_4they’re re-used for reservoir flooding or simply disposed of. Water collected from process operations contains hydrocarbon concentrations too high for safe discharge. Suspended hydrocarbon droplets in water also hinders well-injection.
Challenges: Treatment equipment is similar to three-phase separators except that water is the main product. Level control is found on skim tanks, precipitators, coalescers, flotation units, and collection tanks and sumps. Interface level measurement is essential for proper draining of clean water and removal of the residual oil.
Level Instrumentation:
Point Level:
 ECHOTEL Model 940/941 Ultrasonic Gap Switch; THERMATEL Model TD1/TD2 Thermal Dispersion Switch; or Float or Displacer-actuated Switch
Continuous Level: ECLIPSE Model 706 Transmitter; or E3 MODULEVEL Displacer Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators

Natural Gas Processing


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Level Control Solutions for Natural Gas Applications

The efficiency and safety of natural gas processing applications is dependent on accurate level measurement. With good level control solutions, natural gas processes such as separation, chemical injection and gas dehydration can run smoothly. This blog post discusses level instrumentation for use in natural gas processing applications.

natural_gas_applications_1Separators are large drums designed to separate wellstreams into their individual components. They are commonly designed to separate two-phase (gas/liquid) or three-phase (gas/crude/water) wellstreams. Separators are also classified according to horizontal or vertical configuration (see below), operating pressure, turbulent or laminar flow, and test or production separation.
Challenges: Interface level measurement will actuate a valve to adjust vessel level. An emulsion layer along the oil/water interface can contaminate the oil with water or the water with oil. Foaming along the gas/liquid interface, if entrained, can cause liquid carryover or gas blowby.
Two Principal Types of Separators
Vertical: Vertical separators can accommodate large surges of liquids. They are wellnatural_gas_applications_2 suited for high sediment loads—conical bottoms are sometimes attached for large sediment deposits. Vertical separators are preferred when wellstreams have large liquid-to-gas ratios. These separators occupy less floor space than horizontal types and are often found on offshore platforms where floor space is at a premium.
Horizontal: These separators are well-suited for three-phase separation because of their large interfacial area between the two liquid phases. Horizontal types are preferred when wellstreams have high gas-to-oil ratios, when wellstream flow is more or less constant, and when liquid surges are insignificant. These separators also have a much greater gas/liquid interface area, which aids in the release of solution gas and in the reduction of foaming.natural_gas_application_3
Level Instrumentation:
Point Level: Series 3 Float-actuated External Cage Level Switch; or Thermatel® Model TD1/TD2 Thermal Dispersion Switch
Continuous Level and Interface Level: Eclipse® Model 706 Guided Wave Radar Transmitter; Jupiter® Magnetostrictive Level Transmitter; or E3 Modulevel® Displacer Transmitter
Visual Indication: Atlas™ or Aurora® Magnetic Level Indicators

Chemical agents employed in natural gas processing include drilling fluid additives, methanol injection for freeze protection, glycol injection for hydrate inhibition, produced water treatment chemicals, foam and corrosion inhibitors, de-emulsifiers, desalting chemicals and drag reduction agents. Chemicals are frequently administered by way of natural_gas_applications_4chemical injection skids.
Challenges: Level monitoring controls chemical inventory and determines when the tanks require filling. The careful selection and application of level controls to chemical injection systems can effectively protect against tanks running out of chemicals or overfilling.
Level Instrumentation:
Point Level:
Echotel® Model 961 Ultrasonic Gap Switch; or THERMATEL Model TD1/TD2 Thermal Dispersion Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter; or JUPITER Magnetostrictive Level Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators

Pipeline specifications require removal of the harmful acid gases carbon dioxide (CO2) and hydrogen sulfide (H2S). H2S is highly toxic and corrosive to carbon steels. CO2 is also natural_gas_applications_5corrosive and reduces the BTU value of natural gas. Gas sweetening processes remove these acid gases and make natural gas marketable and suitable for pipeline distribution.
Challenges: Amine treatment removes acid gases through absorption and chemical reaction. Each of the four common amines (MEA, DEA, DGA and MDEA) offer distinct advantages in specific applications. Level control applications include reactors, separators, absorbers, scrubbers and flash tanks.
Level Instrumentation:
Point Level:
ECHOTEL Model 961 Ultrasonic Gap Switch; or THERMATEL Model TD1/TD2 Thermal Dispersion Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators

natural_gas_applications_6A sulfur recovery unit converts the hydrogen sulfide in the acid gas into elemental sulfur. Of the processes available for these conversions, the Claus process is by far the most well-known for recovering elemental sulfur, whereas the conventional Contact Process and the WSA Process are the most used technologies for recovering sulfuric acid. The residual gas from the Claus process is commonly called tail gas. Tail gas is subsequently processed in a gas treating unit.
Challenges: The sulfur condenser vessel is equipped with a disengagement section on the outlet end in order to allow for efficient separation of the liquid sulfur from the process gas. A collection vessel equipped with continuous level control is used to store and remove the sulfur product from the process.
Level Instrumentation:
Point Level:
ECHOTEL Model 961 Ultrasonic Gap Switch; or THERMATEL Model TD1/TD2 Thermal Dispersion Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators

Natural gas dehydration removes hydrates which can grow as crystals and plug lines and retard the flow of gaseous hydrocarbon streams. Dehydration also reduces corrosion, eliminates foaming, and prevents problems with catalysts downstream. Compressor stations typically contain some type of liquid separator to dehydrate natural gas prior to natural_gas_applications_7compression.
Challenges: The most common dehydration method is the absorption of water vapor in the liquid desiccant glycol. The withdrawal of the water rich glycol from the bottom of the absorber is facilitated by a level control. High and low level shut down can be applied to the reboiler, surge tank and flash separator.
Level Instrumentation:
Point Level:
Tuffy® II Float-actuated Switch; ECHOTEL Model 961 Ultrasonic Gap Switch; or THERMATEL TD1/TD2 Thermal Dispersion Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter; or JUPITER Magnetostrictive Transmitter
Visual Indication: ATLAS or AURORA Magnetic Level Indicators

Natural Gas Processing

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A Technical Handbook for Level Instrumentation Application


Utilizing and maintaining level and flow control instrumentation requires knowledge of a wide range of technical information. Having a quick and comprehensive reference point for this information can help keep equipment running smoothly and efficiently. With that in mind, Magnetrol® has produced a free field instrumentation technical handbook featuring a compendium of physical constants, tables and other essential information. The handbook was created by MAGNETROL to cover specific reference points that are commonly used in process applications.

This thorough technical guide features a variety of useful field instrumentation data. Standard conversion tables, such as metric notation conversion and Celsius to Fahrenheit conversion, are included. The technical handbook also includes equivalent tables for viscosity, pressure and head, electrical units, degrees API and degrees baumé. Properties tables feature density, specific gravity and dielectric constants of liquids and gases. Flange dimensions and ratings for pipes are also included. Download the field instrumentation technical handbook today.


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Thermatel® TA2 Nominated for Flow Control Innovation Award

Magnetrol® is pleased to announce that our Thermatel® TA2 thermal dispersion mass flow meter has been nominated for a 2015 Flow Control Innovation Award. This award program recognizes outstanding solutions for fluid movement, measurement and flow_control_innovation_awardscontainment. Flow Control is a widely distributed and well-respected fluid handling publication, and we are proud of the honor to be named a nominee.

The THERMATEL TA2 mass flow meter was recently updated to include an innovative new auto-switching feature, which enables it to automatically switch between calibration tables. This provides the most value in applications in which turndowns can be substantially higher than 100:1. The calibration tables can apply to the same gas, such as natural gas, for a low flow range and a high flow range. They can also measure two different gases with distinct low flow and high flow ranges.

The TA2 has been very successful in flare gas applications in part because of the lack of technologies available to make this measurement. Oftentimes, the gas is at extremely low flows and low pressures. Thermal mass flow meters are the most economical choice and continue to gain ground because of their versatility.

VOTE NOW! You can show your support of MAGNETROL and the innovative THERMATEL TA2 flow meter and have a chance to win a $250 Amazon gift card by voting in the 2015 Flow Control Innovation Awards. Please click here to participate.

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