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.

interface_level_measurement_1

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.

COMPRESSOR LUBRICATION TANK

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

COMPRESSOR SCRUBBER

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

COMPRESSOR WASTE LIQUID

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

FLARE KNOCK-OUT DRUM

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

AIR AND GAS FLOW MONITORING

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.

NGL RECOVERY AND STORAGE
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

VAPOR RECOVERY UNIT FLASH DRUM
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

STORAGE TANKS
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

WATER PROCESSING
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.

INLET SEPARATORS
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 INJECTION
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

AMINE SEPARATION SOUR GAS TREATMENT
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

SULFUR RECOVERY
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

GAS DEHYDRATION
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

level_instrumentation_technical_handbook

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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Key Questions Answered About Thermal Mass Flow Meter Function

Flow Control’s thermal mass flow measurement technology portal provides important information about flow instrumentation and measurement. Tom Kemme, our thermal dispersion product manager, answers questions about the technology in the portal’s Ask the Expert column. This week’s blog shares some recent Q&As.

Question: Does a thermal mass flow meter require temperature compensation during gas flow measurement?

Answer: Yes, thermal mass flow requires temperature compensation. However, this is not the same as the temperature correction you would utilize with a multivariable transmitter or external to flow technologies such as differential pressure in order to obtain Nm3/h, SCFM, SCFH, etc. Thermal manufacturers understand that gas properties that effect heat transfer vary with temperature. The process temperature is already being measured (using a Resistance Temperature Detector) and is accounted for in the calculation.

Question: Can thermal mass flow meters be used with combustible gases?

Answer: Thermal dispersion flow meters can be used in combustible gases. Typically very little heat is added to the system (how much heat depends on the manufacturer). Sometimes customers ask us this question, as they are worried about exceeding the auto-ignition temperature of the particular gas. The maximum temperature rise of our sensor recorded by FM during the approvals process was 4K above ambient. Therefore, this little temperature added to the process temperature does not cause ignition, but it should be evaluated as needed on an application basis with the proper manufacturer.

Question: For wet gases/vapors (e.g., compressed air), what is the maximum allowable moisture content that will allow the thermal mass flow sensor to work without incurring significant error due to heat loss from surface condensation? What size droplets (microns) & mist eliminator efficiency would have to be required to post-treat acid-laden vapor before reaching the temperature sensors? Can the temperature sensor pins be coated with PFA or ETFE for use in corrosive acid vapor service?

Answer: Thermal flow meters are used in applications that have vapors present, as well as gases that are considered “wet,” such as digester gas. If actual condensation is present and it comes into contact with the probe tips, then this can cause a spike in the reading due to the additional cooling of the liquid. There are no specific specs on droplet size.

Liquid drops themselves would not damage the sensor, but corrosion is a different issue. Most manufacturers offer a standard stainless steel probe option, but many have a Hastelloy® option as well, for more corrosive gases. Upon request, other sensor materials can be looked into.

An option when going into an application where condensation could be present would be to install the probe at an angle to prevent the liquid from dripping down the probe and coming into contact with the pins. Thermal flow meters do not have to be installed top dead center of a pipe or duct and can go into horizontal or vertical lines. An example of this is shown here.

Thermal flow meters installed in a pipe

Thermal flow meters installed in a pipe

We would typically not recommend coating of the sensor given the fact it would change the thermal characteristics of the sensor. This could affect sensitivity and achievable flow rates.

As important as accuracy is many times in compressed air applications customers are looking for a relative indication of the amount of leakage. Knowing this measurement assists in calculating the approximate savings by eliminating such leaks. Every flow meter has advantages and disadvantages. For thermal, some of the main advantages are:

  1. Direct mass flow measurement
  2. Strong signal at low flows or low pressures
  3. High turndown

If you have more questions about thermal mass flow meters, you can check out previous answers in the technology portal.

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Level Control for Conversion Applications in the Petroleum Refining Process

The safety and efficiency of every aspect of the petroleum refining process is dependent on accurate level measurement. Reliable instrumentation is especially important in the extreme temperature and pressure environments that are often a part of the process. This blog post explores level instrumentation for conversion applications in the petroleum refining process. This is the third in Magnetrol’s series on level control for petroleum refining. Be sure to check out the previous two posts, from May 26 on treatment applications and from June 9 on separation applications.

CATALYTIC CRACKER

petroleum_refining_process_1The Fluid Catalytic Cracking Unit (FCCU) cracks heavy, low-value feedstocks into high-value, lighter molecular weight hydrocarbons which are blended to finished products. A cracker can produce a wide variety of yield patterns by operating in either Gasoline, Distillate or LPG modes.
Challenges: Catalytic crackers utilize a reactor and a catalyst regenerator with connecting risers where the reactions take place. Level controllers are often positioned on the first stage regenerator and at the top of the reactor. Level measurements involve fluidized solids levels at high temperatures. Conventional measurement techniques can be subject to plugging.
Level Instrumentation:
Continuous Level: E3 Modulevel® Displacer-Actuated Transmitter

CATALYTIC STRIPPER

Variations in cat cracking include Selective Component Cracking (SCC) for polypropylene production, a two-vessel and external-reactor design for processing heavy residue feeds, and a UOP process for converting gas oils and resid feedstocks. All crackers employ a petroleum_refining_processsteam stripper to remove hydrocarbons entrained in the spent catalyst.
Challenges: Stripper level control allows sufficient residence time for stripping steam to displace hydrocarbons for recovery. It also maintains sufficient pressure to keep air in the regenerator from reverse flow into the reaction system, thereby causing a hazard. A waste heat recovery steam drum would also require monitoring.
Level Instrumentation:
Point Level:
Series 3 Float- Actuated External Cage Level Switch or B40 Float-Actuated Level Switch
Continuous Level: E3 MODULEVEL Displacer Transmitter or Eclipse® Model 706 Guided Wave Radar Transmitter
Visual Indication: Orion® Instruments Atlas™ or Aurora® Magnetic Level Indicators

HYDROCRACKING

Heavier feedstock difficult to process by cat cracking or reforming can be converted by hydrocracking. By combining catalytic cracking and hydrogenation to crack feedstock in the presence of hydrogen, hydrocracking produces gasoline and distillate blending streams. About a dozen different hydrocracking process schemes are in current use.
petroleum_refining_process_3Challenges: Level controls for the catalyst stripper, separator liquid and flash drum liquid must contend with severe process conditions to maintain optimum operation of the hydrocracker. These conditions include elevated temperatures and pressures, the presence of steam and high pressure hydrogen, and aggressive corrosives.
Level Instrumentation:
Point Level:
Series 3 Float-Actuated External Cage Level Switch or Model B40 Float- Actuated Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION INSTRUMENTS ATLAS or AURORA Magnetic Level Indicators

ACID SETTLING TANKS

Alkylation is a combining process that creates alkylate, a premium, high-octane blending petroleum_refining_process_4stock. A large acid settler tank within the unit allows for separation of the acid/hydrocarbon emulsion created in the reactor. Sight glasses have traditionally measured settler level, but these are susceptible to plugging and require diligent flushing at regular intervals.
Challenges: Interface level control of the settler is required. Product/acid cross-contamination causes overall efficiency problems and can result in hazardous conditions. Inaccurate settler level indication is a frequent cause of physical acid carryover in the reactor effluent. Release of acid can cause extreme hazards to both process and personnel.
Level Instrumentation:
Point Level: Model A15 Displacer- Actuated Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION INSTRUMENTS ATLAS or AURORA Magnetic Level Indicators

ALKYLATION TANKS

Storage and wash vessels in the alkylation unit include those for fresh and depleted acid and water, an acid analyzer settling pot, and a number of wash tanks. Caustic washes petroleum_refining_process_5neutralize free acid carried over from the reaction zone and neutralize alkyl sulfates in the net effluent. Water washes decompose remaining esters and remove caustic and salt that might have carried over from the caustic wash.
Challenges: Interface level control in caustic and water washes prevents corrosion and fouling of the deisobutanizer and other downstream units. Levels rising above high set points can cause carryover of caustic or water, while too low levels can cause hydrocarbon carryunder.
Level Instrumentation:
Point Level:
Series 3 Float- Actuated External Cage Level Switch
Continuous Level: E3 MODULEVEL Displacer- Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter or Pulsar® Model RX5 Pulse Burst Transmitter
Visual Indication: ORION INSTRUMENTS ATLAS or AURORA Magnetic Level Indicators

CATALYTIC REFORMER

Catalytic reforming upgrades low-octane naphthas into high-octane gasoline blending components called reformates. Using heat and pressure with platinum catalysts to petroleum_refining_process_6rearrange hydrocarbon molecules, this process converts low-octane gasoline fractions into petrochemical feedstocks and higher octane stocks suitable for finished gasoline blending.
Challenges: A hydrogen-rich gas stream is removed from the separator for recycling. Liquid product monitored for level at the bottom of the separator is sent to a stabilizer. Where stabilizer fouling has occurred due to the formation of ammonium chloride and iron salts, a monitored water wash system should also be included.
Level Instrumentation:
Point Level:
Series 3 Float- Actuated External Cage Level Switch
Continuous Level: E3 MODULEVEL Displacer- Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter or PULSAR Model RX5 Pulse Burst Transmitter
Visual Indication: ORION INSTRUMENTS ATLAS or AURORA Magnetic Level Indicators

COKING OPERATIONS

Coking is the final means of converting the heaviest products of atmospheric and vacuum distillation. Feed is heated and cracked into light gases, gasoline blendstocks, distillates, and gas oil. Level applications for delayed and continuous (contact or fluid) coking include petroleum_refining_process_7the fractionator, light gas oil stripper, steam, condensate, blowdown and settling drums, and vent gas knockout drums.
Challenges: Process conditions that level instrumentation must contend with include high temperatures, high pressures, foaming, and steam. An interface level gauge in drums that are susceptible to foaming will help avoid foam-over and increase coke drum output.
Level Instrumentation:
Point Level: Series 3 Float- Actuated External Cage Level Switch or B40 Float- Actuated Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION INSTRUMENTS ATLAS or AURORA Magnetic Level Indicators

ISOMERIZATION

petroleum_refining_process_8Isomerization in a variety of process configurations alters the arrangement of atoms to convert normal butane into isobutane, and normal pentane and hexane into high-octane gasoline components. Isomerization is similar to catalytic reforming in that the hydrocarbon molecules are rearranged, though isomerization only converts normal paraffins to isoparaffins.
Challenges: Near the end of the process, reactor effluent is cooled and separated into the liquid product isomerate and a recycle hydrogen-gas stream. Isomerate is caustic-washed and water-washed, acid stripped, and stabilized before going to storage. Stabilizer bottoms and wash tanks require level monitoring.
Level Instrumentation:
Point Level:
Model A15 Displacer- Actuated Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter; or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION INSTRUMENTS ATLAS or AURORA Magnetic Level Indicators

Petroleum Refining Process Applications

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Level Control for Separation Applications in the Petroleum Refining Process

Reliable level measurement is needed to ensure safety and efficiency throughout the petroleum refining process, particularly in high temperature and high pressure environments. There are a wide range of level control applications for separation operations in petroleum processing. This blog post is the second in a Magnetrol® series on level instrumentation for petroleum refining. Be sure to check out the previous post, from May 26, on level control for treatment applications.

CRUDE STORAGE
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Upon arrival at the refinery terminal, crude oil is pumped into above-ground storage tanks with capacities of thousands to millions of gallons. Raw crude is stored in floating- or fixed-roof tanks field-built to API standards. Tank level measurement by noncontact radar has gained share over mechanical float type and servo gauges due to its accuracy, low maintenance, no moving parts and fast set-up.

Challenges:
Tank level is maintained by valve actuation. By triggering an emergency cutoff, level controls prevent overflows and shut down pumps when level falls below low level. Safety-certified controls may be necessary due to crude’s low flash point.

Level Technologies:
Point Level:
Model A15 Displacer-Actuated Level Switch
Continuous Level: Pulsar® Model RX5 Non-Contact (Pulse Burst) Radar Transmitter; or Eclipse® Model 706 Guided Wave Radar Transmitter with 7X7 Flexible Twin Rod Probe

CRUDE DEWATERING
All unrefined crude oil stored in tanks has a percentage of water entrained within it, and while stored in tanks, separation naturally occurs with water collecting at the bottom of the tank beneath the oil. The two fluids are very distinct except for a “black water” or “rag” interface layer which is an emulsion of mixed oil and water. To dewater the tank, water ispetroleum_refining_process_2 drawn off of the bottom of the tank and is then sent off to water treatment.

Challenges:
Level controls designed for interface detection will sense the beginning of the oil/water interface during dewatering procedures and provide feedback to a control system which will terminate water draw-off when appropriate.

Level Instrumentation:
Point Level: Model A15 Displacer-Actuated Level Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter; or E3 Modulevel® Displacer-Actuated Transmitter

CRUDE DESALTING
Inorganic chlorides, suspended solids, and trace metals found in untreated crude must be removed by chemical or electrostatic desalting. This reduces the risk of acid corrosion, petroleum_refining_process_3plugging, fouling and catalyst poisoning in downstream units. Measurement of the oil/water interface in the desalter is crucial in separating the cleansed crude from contaminants.

Challenges:
Coating and build-up on probes may create interface measurement errors. Instruments susceptible to electrostatic grid interference may require special filters. Interface-dedicated level transmitters fitted with quick-disconnect probes provide optimum performance while reducing cleaning and maintenance time.

Level Instrumentation:
Point Level:
Model A15 Displacer-Actuated Level Switch
Continuous Level: ECLIPSE Model 706 Guided Wave Radar Transmitter; or E3 MODULEVEL Displacer-Actuated Transmitter

PREFLASH DRUM
Located in the preheat train of the distillation column, a preflash drum system separates petroleum_refining_process_4the vapors generated by preheating before entering the heater or main column. This prevents higher heater firing or pressure drops and reduces vapor loading of the column to avoid flooding.

Challenges:
Preflash drums create moderate foam that can affect measurement accuracy of liquid levels and decrease distillate production in the atmospheric column. Too low of a pre- flash drum level will cause pump cavitation of the flashed crude. Too high of a level will cause liquid carryover to the distillation column.

Level Instrumentation:
Point Level: Series 3 Float-Actuated External Cage Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter; or ECLIPSE Model 705 Guided Wave Radar Transmitter
Visual Indication: Orion® Instruments Atlas™ or Aurora® Magnetic Level Indicators

DISTILLATION COLUMN
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Following desalination, crude oil enters the distillation column where fractional distillation separates hydrocarbons into separate streams, cuts or fractions. For optimum operation of the distillation column, level controls must contend with occurrences of foaming, bubbling and moderate-to-high temperatures.

Challenges:
Sight glasses and displacer systems mounted in external chambers have traditionally provided distillation level measurement. Today, radar retrofitted in these existing chambers is gaining popularity due to radar’s less demanding maintenance schedule and ease of retrofit. High product temperatures necessitate temperature-tolerant level sensors.

Level Instrumentation:
Point Level: Series 3 Float-Actuated External Cage Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION Instruments ATLAS or AURORA Magnetic Level Indicators

REFLUX ACCUMULATOR
A heat exchanger removes vapor from the upper parts of the fractionator, cools it to a liquid, and pumps it into an accumulator (reflux drum). Reflux pumps then draw liquid from the bottom of the accumulator and pump part of it back (reflux) where it is reintroduced at a lower point in the column. This refluxing process improves separation inpetroleum_refining_process_6 the column by assuring sufficient downward liquid flow meeting the rising vapor.

Challenges:
Accurate and reliable level monitoring and control is necessary for the reflux accumulator to serve as a distribution point for reflux and distillate, and prevent excessive reflux from returning back to the tower.

Level Instrumentation:
Point Level: Series 3 Float-Actuated External Cage Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION Instruments ATLAS or AURORA Magnetic Level Indicators

COLUMN REBOILER
A heat exchanger positioned near the bottom of the distillation column re-heats and vaporizes liquid and reintroduces the vapor several trays higher. This improves separation petroleum_refining_process_7by introducing more heat into the column. For effective functioning of the reboiling process, level monitoring of the reboiler is required.

Challenges:
In some steam reboilers, the level must be controlled so that only a percentage of tubes are covered. This allows a control scheme to regulate the heat transfer in the reboiler by controlling the percentage of the reboiler tubes covered by liquid. This is a critical control loop as heat transfer into the liquid is a strong function of the percentage of tubes covered.

Level Instrumentation:
Point Level: Series 3 Float-Actuated External Cage Level Switch or Tuffy® II Float- Actuated Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION Instruments ATLAS or AURORA Magnetic Level Indicators

SOLVENT EXTRACTION
The heavy fraction remaining following the distillation of crudes is called petroleum resids. A variety of solvent-extraction processes yield deasphalted oil (DAO) from these petroleum_refining_process_8resids. These oils serve as downstream feedstocks for catalytic crackers and hydrocrackers. Depending upon the system configuration, level monitoring of the separator, pre-flash, stripper and hot oil phases may include surge and flash drums, separators and strippers.

Challenges:
Level control is critical because interface level control of the separator feeds the flash drum, whose level feeds the stripper, etc. Application extremes include high temperatures, high pressures, and the presence of steam.

Level Instrumentation:
Point Level:
Series 3 Float-Actuated External Cage Level Switch
Continuous Level: E3 MODULEVEL Displacer-Actuated Transmitter or ECLIPSE Model 706 Guided Wave Radar Transmitter
Visual Indication: ORION Instruments ATLAS or AURORA Magnetic Level Indicators

Petroleum Refining Process Applications 

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Magnetrol® Announces Higher Process Temperature Ratings for E3 Modulevel® Displacer Level Transmitter

E3_ModulevelMagnetrol® International has announced the release of the E3 Modulevel® displacer level transmitter with an increased upper temperature rating. E3 MODULEVEL transmitters now handle process temperatures of up to +850o F (+454o C) for non-steam applications and +800o F (+427o C) for steam applications. This capability helps protect downstream equipment by providing accurate, reliable liquid and interface level control in extreme process conditions.

Using linear variable differential transformer (LVDT)/range spring technology, E3 MODULEVEL transmitters offer outstanding output stability, structural integrity and ease of use. Vertical in-line design of the transmitter results in low instrument weight and simplified installation.

For a technology overview of E3 MODULEVEL transmitters, visit e3modulevel.magnetrol.com or contact info@magnetrol.com for more information.

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