An oil mist lubrication system is a widely used bearing lubrication. A centralized lubrication system generates and automatically delivers the lubricant to machinery bearings to keep them lubricated for making moving parts reliable. The fine mixture of oil and air that is generated is called oil mist. Oil-mist lubrication ensures a high standard of lubrication as and when required and prevents the ingress of contaminants to the bearing housing.
Various Types of Lubrication
Splash Lubrication
Grease Lubrication
Forced Lubrication
Solid Lubrication
Mist Lubrication
Oil Mist System is a means of generating and transporting a finely dispersed oil mist from a central location to individual bearing housings.
The oil mist system uses compressed air to atomize oil into micron-size particles which can be effectively moved to lubrication points up to 600 feet (180 meters) through Pipes & Tubes
One Oil Mist system can provide lubrication to 60 pumps and their drivers with approximate oil consumption of one gallon (3.8L) of oil per 24 hours.
Typical Oil Mist System
Refer to Fig. 1 which shows a typical oil mist lubrication system used for industrial applications.
Fig. 1: Typical Oil Mist System
Types of Oil Mist Lubrication Systems
The oil mist lubrication system can be categorized into the following types.
Open Loop System (Fig. 2)
Closed-Loop System (Fig. 2)
Dry Sump (Pure Mist-Fig. 3)
Wet Sump (Purge Mist-Fig. 3)
Fig. 2: Open and Closed Loop Mist Lubrication System
Pure & Purge Mist Lubrication
Pure Mist Lubrication System-
The bearing is lubricated by oil mist, not oil.
Bearings can run 10-15 degC cooler with pure mist as compared to sump lubrication.
The bearing housing is pressurized by continuous oil mist flow, then external contaminants (dust, moisture…) are excluded.
Centrally controlled hence attention to oil level is not required individually.
Purge Mist Lubrication System-
The bearing is lubricated by oil, not oil mist.
The bearing housing is pressurized by continuous oil mist flow, then external contaminants (dust, moisture…) are excluded.
Here mist purges the bearing housing and provides partial fresh Makeup oil.
Oil levels must be checked and maintained for each piece of equipment.
Fig. 3 below shows typical pure and purge mist lubrication systems.
Fig. 3: Pure and Purge Mist Lubrication
Components of Oil-Mist Lubrication Systems
The major components of the oil-mist lubrication system are listed below:
Oil mist generator- the heart of the oil mist lubrication system, compressed air is passed through a venturi or vortex to produce the oil-mist mixture.
Oil mist cabinet-Stainless steel cabinet.
Reclassifiers- Controls the mist flow to applicable points. Bearing type, shaft speed, and diameter dictate the sizing of reclassifiers.
Air- Clean and Dry air free from toxic, corrosive, and flammable elements.
Air Filter at the air inlet.
Air regulator to control supply air pressure
Air Pre-Heater-For cold climates to maintain the air temperature
While selecting the oil for an oil-mist lubrication system, the following factors need to be considered:
Oil Viscosity at the operating temperature
Pour point
Surface tension
Solidification tendency of the oil at low ambient temperatures
How does oil mist Lubrication lubricates the bearing?
The following figure (Fig. 4) shows the working of the oil-mist lubrication system to enhance bearing life.
Fig. 4: Working of Oil-Mist Lubrication System
Mist Lubrication Suitability
Rolling element and sliding contact bearings can be lubricated with Oil Mist either Pure or Purge type.
Oil mist is used to lubricate rolling element bearings of all types. Ball & Roller bearings are generally applied with Pure Mist Lubrication.
When sliding contact bearings are used, oil mist alone does not provide complete lubrication & hence, an oil level is maintained in the bearing housing and is called Purge Mist Lubrication.
Advantages of Oil Mist Lubrication System
Oil mist lubrication system offers various advantages over the other lubrication systems as listed below
Prevent the dust/moisture ingress into bearing housing, due to the pressurized system
Increased Bearing Life
Lower friction and thus reduced bearing temperatures
Reduced maintenance, reduced handling, and spillage.
As the bearings operate in a thin film of oil, so less power is required.
Reduced Oil consumption (40% less & 50% of it can be recovered)
More environmentally friendly than the conventional lubrication system.
As the oil on the bearings is always new, it provides better lubricant properties.
In technical papers released by end-users and bearing manufacturers, as well as in university research, bearings lubricated with oil mist have a longer life than bearings lubricated with oil sump or grease. Users report from a 50% to 90% reduction in lubrication-related bearing failures.
Finally, it is economic to use.
Disadvantages of Oil Mist Lubrication System
Even though mist lubrication systems have various advantages and reduce maintenance and operating problems, still there are a few disadvantages of this system such as
Relay on Instrument Air System
LSC is the single vendor of the Oil Mist System for Hydrocarbon Processing Industries
An oil mist system is almost trouble-free but it cannot be installed and forgotten. Systems should be checked daily for correct air and oil temperature, oil level, and mist header pressure along with other weekly and monthly maintenance programs.
The oil-mist lubrication system involves environmental hazards. OSHA requirement states that a person shall not be exposed to more than five milligrams of oil per cubic meter of air in an eight-hour period.
The performance of the oil mist lubrication system is sensitive to temperature.
Corrosion can be defined as the deterioration of materials under the influence of an environment. Without exception, the corrosion of metals and alloys (a majority of materials used in industry) in aqueous environments (the most often encountered environment) is an electrochemical reaction.
Factors affecting Corrosion
Corrosion behavior depends on the following factors:
Fig. 1 shows the normal types of Corrosion that are prevalent in the Oil and Gas Industry.
Fig. 1: Types of Corrosion in the Oil and Gas industry
Uniform Corrosion
Though uniform corrosion is an idealized form of corrosion and because of less damage than the other forms of corrosion, it is more appropriate to understand this form of corrosion. This leads to uniform thinning of the structures.
Units of Corrosion | Corrosion Measurement
The corrosion attack is measured in terms of penetration. Corrosion is expressed in the units mpy (mills per year) or mm per year. This can be determined by any gravimetric method.
When dissimilar metals or alloys differing in their galvanic or corrosion potential are employed and if they are electrically shorted they induce this type of corrosion. The corrosion rate of the alloy with lower corrosion potential will be accelerated by that of higher corrosion potential.
Identification of Galvanic Corrosion
The active metal is corroded
Grooving of the interface
Noble metal deposits from the stream
Graphite lining or bricks
Prevention of Galvanic Corrosion
Provide electrical insulation between the metal
Choose alloys closer to the galvanic series
Provide design in structure so as to make anodic to cathodic ratio extremely large.
Coat both anode and cathodic areas. Otherwise, coat only the cathode.
Protect the corroding metal with a sacrificial anode, which is anodic to the corroding metal.
Crevice Corrosion
Accelerated corrosion occurs if differential aeration exists due to crevice, metal joining (lap joints, flanges, etc.), or any deposits. Interestingly the location starving for oxygen is forced to become anodic and the region having free access to oxygen becomes the cathode.
Identification of Crevice Corrosion
Rivets, flanges, and lap joints are attacked internally.
Deposits such as corrosion products, organic deposits, growth of organisms, etc. cause corrosion.
Improper drainage of vessels and pipelines causes an accelerated attack.
Prevention of Crevice Corrosion
Avoid riveting, go in for welding
Design for proper drainage
For stainless steels, high Mo content (316, 317, and Hastelloy) reduces crevice corrosion
Remove the deposits
Use solid non-absorbent gaskets
Pitting Corrosion
Alloys in presence of certain ions (such as halides) are prone to pitting. The rate of penetration within the pit can be as high as one million times as compared to the surroundings.
Identification of Pitting Corrosion
Pinholes
Normally grow in the direction of gravity
The alloy environment combination is likely to promote pitting
Pitting has taken place along the inclusion
Prevention of Pitting Corrosion
Eliminate the specific ions responsible for pitting (say halides in the case of SS)
Choose an alloy resistant to pitting. In stainless steels, high Mo promotes resistance (haste alloys, duplex stainless steels)
Mild steels serve better in a chloride environment than SS if a certain amount of uniform corrosion is tolerated. Monel has more resistance in this environment.
Selective Leaching (De-Zincification)
When noble and active elements form an alloy it results in the selective removal of the latter. As a consequence, the alloy loses its strength and fails prematurely. Cu-Zn alloys are well known wherein dezincification occurs if Zn content exceeds 15 wl. Similarly, there is de-nickelification, de-siliconation, de-cobaltification.
Identification of Leaching
They give rise to plug and layered types of attack.
Change in color (from yellow to brown in the cases of brasses)
X-ray diffraction can sometimes reveal the selective removal of one element
There can be a change in density in some cases.
Prevention of Leaching
Addition of any one of the elements namely Sn, As, Sb and P
Al addition reduces overall corrosion and to some extent dezincification.
Intergranular Corrosion
This type of corrosion occurs as a result of a selective attack of the grain boundaries when either the grain boundary becomes highly active or phases prone to selective attack are formed. Stainless steels, which are normally resistant to intergranular attack, when subjected to a heat treatment between 400-900 C become sensitive to intergranular corrosion (IGC). This range can vary depending on the composition of the alloy. This treatment is called sensitization treatment and the alloy is said to be sensitized. This is mainly due to the formation of Cr23C6 and the consequent grain boundary depletion. Welding, a common practice in fabrication causes such an IGC attack.
Identification of Intergranular Corrosion
The attack of the alloy away from the weldment is called a heat-affected zone.
Clear ditch type of attack along the grain boundary and consequent weakening seen at higher magnification.
Prevention of Intergranular Corrosion
Choose low-carbon and extra-low-carbon stainless steels (such SS are 3041,3161,3171)
Choose Ti or Ta and Nb containing alloys (321,347)
Provide a solutions treatment to redissolve the carbides (1050 °C, 30 m)
Erosion Corrosion
When there is a relative movement of the corrosive environment with respect to the alloy it can lead to erosion-corrosion. Pipelines and heat exchangers are subjected to such a kind of failure.
Identification of Erosion Corrosion
Attack at the bends in pipelines
Grooves in the direction of liquid flow.
Prevention of Erosion Corrosion
Reduce the velocity of the medium
Choose hard materials
Avoid sharp turns
Provide hard coatings.
Cavitation Damage
Some variation in erosion-corrosion is cavitation damage. Here there is damage due to bubble formation and collapse when there is hydrodynamic variation in pressure difference along the line. At low-pressure water/liquid vaporizes. When the same is subjected to higher pressure bubble forms and subsequently implodes. This leads to plastic deformation and the formation of cavities as brought out in.
Fretting Damage
Moving/vibrating interfaces under load cause damage akin to wear called fretting damage. Here the relative movement is relatively small in angstroms. A typical failed surface under this process is brought out.
Stress Corrosion Cracking (SCC)
When there is a conjoint action of stress and environment. Stress corrosion cracking occurs (SCC). However, SCC is specific to an environment. The alloys are susceptible to SCC only when specific ions are present akin to pitting corrosion. In addition, the alloys fail only if the stress exceeds a threshold level below which they are safe.
Identification of SCC
SCC in austenitic stainless steel is predominantly trans-granular in nature.
Failure occurs by brittle mode.
Ions promoting the SCC of that particular alloy must be present. Say Cl and O2 for austenitic SS and ammoniacal solution for Cu base alloys.
If the alloy is sensitized it can promote an intergranular mode of cracking.
Prevention of SCC
Select the alloy that is not susceptible to the environment.
In the case of SS, control either Cr or O2 one can keep either one of the low.
Apply load lower than the threshold stress.
Provide compressive stresses by sandblasting or shot blasting.
Avoid stress concentration.
Corrosion rates for a few materials
The following table provides some typical atmospheric corrosion rate values in mils/yr for some common materials
Atmospheric Corrosion rates (mils/yr)
Material
Rural
Industrial
Marine
Severe
A 242 type 1
0.05-0.16
0.06-0.60
0.17-0.37
0.83-2.20
A 514 type B
0.06-0.20
0.06-0.40
0.20-0.70
0.10-0.50
A 514 type F
–
0.34-1.60
0.30-1.00
0.53-0.70
A 517 type B
0.06-0.26
0.06-1.60
0.19-1.00
0.11-0.70
A 588 Gr A
0.10-0.24
0.14-0.47
0.25-0.80
3.05-4.1
Structural Steel
0.15-0.29
0.17-0.73
0.37-0.90
7.20-9.0
Stainless Steel
Only Pitting, No general corrosion
Table: Typical Atmospheric Corrosion rates for some Materials (ASM Handbook of Corrosion data)
Vertical Reboilers play a significant role in the Process industry. Reboilers are a type of Heat exchanger that is used for heating the bottom fluid of industrial Distillation columns. Normally heat from steam (or any other high-temperature fluid) is utilized to boil the liquid from the bottom of a Distillation Column. Normally this heating effect generates vapor which is then returned back to the Column at a higher elevation to drive the distillation separation.
The piping arrangement between the distillation column and reboiler for this action is normally very stiff and requires careful Analysis to keep the column and Reboiler nozzle loadings within an acceptable limit. The following article will provide the Stress analysis methodology of a vertical Reboiler connected piping system using the software tool Caesar II, developed by Coade Inc.
Applicable codes and standards for Reboiler Piping Stress Analysis
ASME B 31.3-Process Piping,
ASME Section VIII-Pressure Vessel design (Normally distillation columns and reboilers are manufactured based on these codes),
Column and Reboiler allowable nozzle Loads (Should be taken from Equipment Vendor in case no standard Project-specific load is not available)
Temperature Profile for Modeling the Rebolier and Column
Column Temperature
In the absence of project-specific guidelines, the Operating/ Design temperature of the Column shall be considered the same as the average operating/design temperature of the column outlet piping attached to each draw-off nozzle
Reboiler Temperature
The Reboiler modeling uses the following information in the absence of project-specific guidelines:
Tube side Inlet Temperature = bottom (outlet) Piping temperature of the tower.
The temperature of the tube = average temperature between tube inlet and outlet piping.
Tube side outlet temperature = temperature of the tower inlet piping.
If the temperature of the Column inlet piping (channel outlet) is not known, consider the reboiler tube outlet temperature as mentioned in the vendor drawing or confirm from the process engineer.
Shell side temperature = average of the Shell inlet (Normally Steam) and outlet piping (Normally Condensate).
Modeling of the Reboiler with an Expansion joint in Caesar II
Initially model the reboiler as a rigid body following the below-mentioned steps. Refer attached drawing (Fig. 1) as a reference:
1. Model nodes 10-20 and 20-30 with tube outlet temperature and pressure considering channel material, diameter, thickness, length, and fluid density (Also include insulation thickness and density if any) from Rebolier General Arrangement (Henceforth called GA) drawing.
2. Model nodes 30-40, 40-50, and 60-70 with shell average temperature and shell design pressure considering shell material and dimensions as mentioned in reboiler GA.
3. Model element 30-70 with Channelside average temperature and design pressure taking tube material, shell diameter, and thickness from GA drawing.
4. Model 70-80 and 80-90 with tube inlet temperature and pressure considering channel material, diameter, thickness, and length.
Fig. 1: Reboiler piping schematic diagram for modeling in Caesar II
5. Model elements 50-100 with shell-side properties and model the support restraint at node 100. Similarly model all other support elements as required from the GA drawing (check 2 lugs, 3 lugs or 4 lugs supported system).
6. Now make the elements 10-20, 20-30, and 70-80 as flexible (i.e, non-rigid)
7. Check the total operating weight of the reboiler from GA (if operating weight is not available assume 70% of water-filled weight) and the weight already considered in elements mentioned in step no 6 (considering fluid and insulation; you can do it easily by clicking the single run button in caesar II). Provide the remaining balance weight in rigid element 30-70 (tube weight). Recheck once again by clicking the single run button to ensure the actual weight in the caesar model matches the weight provided in GA.
In case there is no expansion joint in the shell, model element 30-70 with shell-side average temperature. Rest all other parameters will remain the same.
As you are planning for reboiler piping I am sure you know the modeling of the column and attached piping. So I am not describing it. So model the column and attached piping to make a complete system as shown in the attached figure (Fig. 1).
Supporting Arrangement for Vertical Reboiler Piping
Reboilers may be supported by the column or by making an independent structure. In both of cases, there is a possibility to support the reboiler lugs directly on the structure or there may be a requirement for spring hangers (bottom mounted). Sometimes Slot holes and PTFE/graphite sliding plates are required to reduce frictional effects. So this information needs to be informed to the equipment vendor. Location of the lugs to be fixed in such a manner with respect to nozzles, bellows, and other accessories to avoid fouling, etc. If the reboiler is supported on spring supports (See attached figure Fig. 2) then the following points need to be considered:
Cold/Hot Load Conditions should be the same for all the springs
Spring should be designed keeping in consideration the empty weight of the reboiler in case of standby and steam out condition.
Slotted Holes are not required on the lug of reboiler in case of spring support
Fig. 2 : Supporting Arrangement of Vertical Reboiler Piping using Spring hangers
Mirror polished SS plates/PTFE plates if required are to be provided by the vendor
If the loads on nozzle are quite large because of the back force due to spring in WNC Case, the Lock Nut (Refer above figure) can be provided on spring to act as the limit stop.
The required gap shall be input in Caesar as a gap on restraint applied at spring in (negative Y) Direction.
The pipe stress Engineer has to provide details of the Lock Nut (See the figure attached below, Fig 3) and the loads on the nut in the Spring Datasheet.
Fig. 3: Locknut arrangement for Reboiler Piping Supporting
Load cases for Reboiler Piping analysis
Load cases are to be prepared based on operation possibility. So one must consult with the process engineer to know all the possible load cases. Normal possibilities are mentioned below:
1. Operating temperature load cases (W+P1+T1)
2. Design temperature load cases (W+P1+T2)
3. Steam out temperature load cases (W+P1+T3)
4. Upset Condition load cases (W+P1+T4): This condition may arise if the fluid is flowing in one part of the reboiler and no fluid is flowing through the other. Normally during start-up, these types of cases may appear. Sometimes it may happen that you have to first heat the reboiler shell before you can start the flow of process fluid through the tubes. Consultation must be done with the process engineer while creating all such load cases.
5. Sustained load cases (W+P1)
6. Prepare all occasional and expansion load cases as per normal project procedures. It is sometimes required that two or three reboilers of similar type are connected to the same column. In this case, some reboiler may be in standby condition. So that situation is also required to be interpreted while making load cases. So additional load cases need to be added accordingly.
Few Important Notes related to Re-boiler Piping Stress Analysis
Reboiler column circuits being one of the most critical systems from a stress analysis point of view one should take extreme care while analyzing such systems. The following notes will help the stress engineer to take an engineering judgment:
1)All of the junctions between the shell & nozzle can be considered as reinforced after confirmation from the Mechanical Department
2)If nozzle loads exceed the allowable, loads should be forwarded to mechanical for further evaluation. Alternatively, the stress engineer has to perform WRC or FEA to qualify the nozzle loads. It is better to forward the WRC/FEA output results to Mechanical for their review.
3)Nozzle loads should be checked thoroughly with the spring setting when the reboiler is on standby during steam out.
4)Flange leakage evaluation should be performed as per client requirement and the rating of flanges should be changed if required, and the same information should be forwarded to the Mechanical and Process Team.
5)Initially, the Nozzle loads are to be forwarded to mechanical as three times the project-specific pressure vessel loads in Caesar to take care of the upset conditions.
6) The requirement of Spring supports, PTFE/SS plates, Slot holes, Locknut arrangement, etc. is to be marked in the Engineering drawing for incorporation into the final vendor drawing.
7) Location of lug to be fixed in such a manner with respect to nozzles, bellows, and other accessories to avoid fouling, etc.
8) Fouling of the Reboiler Nozzle (Shell Outlet) with structure should be checked.
Pipe Heat Tracing is a generalized term relating to the application of radiant heat input to piping systems from tubing attached to the outside of the pipe. Heat tracing is a process requirement. Pipes carrying higher fluid temperatures than the ambient temperature will lose temperature to the surrounding. Insulation is a way to reduce this loss. But insulation is not 100% foolproof. So to make up for that heat loss, small-bore steam pipes or electrical wires (known as heat tracers) are attached to the parent pipe. This system is called the heat tracing of piping.
Purpose of Heat Tracing
Heat tracing serves various other purposes as listed below:
Maintaining the required temperature for the process fluid.
In Steam tracing (Fig. 1) of piping, steam is circulated through tubes that run alongside the pipes to keep the process fluid at the desired temperature. Other fluids like organics, glycols, etc can be used as tracing fluid in heat tracing system design. However, there are various advantages of using steam as heat tracing fluid as mentioned below:
The cost of steam generation is less as compared to other fluids. So steam tracing is economical.
The maintenance cost is also low. Once, the steam tracing network is installed, less maintenance costs will be involved.
Steam tracing of piping is highly energy efficient.
Pipe Steam tracing heats up the process fluid quickly.
No pumping is required for steam.
Temperature control in steam tracing is high.
Fig. 1: Steam Tracing Example
Electrical tracing
On the other hand, in electric tracing (Fig. 2) of the piping system, an electrical heating element transfers heat into the process fluid while running in physical contact along the pipe length. Heat is normally generated in an electrically resistive element. However, other effects like impedance, induction, skin conduction, etc can be utilized in electrical tracing. Electrical heat tracing is also known as cable heat tracing.
Fig. 2: Electric Tracing
Pipe Heat Tracing Cable
Appropriate heat tracing cable for electrical tracing is determined based on the following parameters:
Three types of pipe heat tracing cables are used for industrial electrical tracing systems. They are:
Self-regulating polymer jacketed cables: These heat trace cables are suitable for temperatures up to 200°C and circuit lengths of up to 750 feet.
Mineral insulated heat trace cables: Such heat tracing cables are used for a temperature of up to 650°C and circuit lengths of up to 3,300 feet.
Skin effect heating system cables: For moderate temperature ranges and much longer heating circuits, skin effect heat trace cables are used. They can be used up to 82,000 feet (25 km) in length and their rated temperature is up to 250°C.
Controlling heat tracing temperature for electrical tracing is very important. Various control panels are used for heat tracing temperature control. The heat tracing system shall be suitable for operation on 240V + 5%, 50 Hz, single-phase AC supply. The Power supply to the heater tapes/heat tracing cables shall be from local distribution panels (LDPs) located in the field at strategic locations /load centers to be decided by the contractor. However, the main Power Distribution Panel shall be located in Switchgear Room in a safe area.
Piping Heat Tracing tapes / Heating Tapes
Heat tracing cables are also known as heat tracing tapes. Industrial heat tracing tapes or heating tapes should possess the following characteristics:
Heat tracing tapes should easily wrap around the pipe or equipment.
Heating tapes should provide intimate contact with the pipe material for higher efficiency of heat transfer.
Heat tracing tapes should be fast in heating up.
Heating Tapes should be able to withstand higher required temperatures.
Heat tracing tapes or heat tracing cables must be durable and long-lasting
Additionally, the heating tapes should possess the following features:
To prevent damage during over-lapping, the heating tapes shall have a burn-out-proof feature.
The heating tapes shall be suitable for use in the area defined in the process datasheets. Corrosion-resistant metallic braid must be provided for safe and hazardous area applications.
In hazardous area applications, the surface temperature of the heating tapes shall not exceed 200 deg. C.
For valves, flanges, pipe supports, and similar heat sinks, an extra heater tape length shall be provided. The heater tapes to be installed should consider easy maintenance or removal of the valve, and pipe support.
Heat tape surfaces must be cleaned before the installation of heater tapes on pipes and other equipment.
Advantages and Disadvantages of Piping Heat Tracing using Fluids or Electricity
The following figure shows the principal features of different types of heat tracing methods.
Fig. 3: Steam Tracing vs Electrical tracing
When Heat tracing is used to ensure that the system functions from a process standpoint regardless of climate conditions it is known as Process Control Tracing
Again when Heat tracing is used to prevent freeze-up due to climatic conditions only it is known as Winterization Tracing.
Heat tracing Design Steps
The following steps are followed for designing a pipe heat tracing system:
Calculation of heat loss from the pipe or equipment.
Adjust the heat loss for the insulation system.
Correct that heat loss considering wind speed and additional safety factor (margin).
So this calculated value will be used as input for heat tracing system design. The heat tracing system should add at least that much heat to the piping system to maintain the required heat (temperature) in the process fluid.
General Requirements for Piping Heat Tracing
General rules for Steam Tracing
Steam tracing supply lines shall be taken from the top of the supply header to assure dry-quality steam.
Identify the locations for steam tracing supply manifolds and condensate manifolds early in design to reserve space in plant layout. This applies to non-steam supply and returns manifolds (hot oil, glycol, etc.).
Allow for an increase in insulation sizing to allow for tracers.
Instrument Application for heat tracing
In-line instruments can also be required to be heat traced as process condition dictates. In that case, Piping needs to provide steam supply and condensate collection manifolds for all other instruments. The break between Piping Traced Instruments and Control Systems traced instruments will match the drawing break between the two departments.
Heat Tracing System Description
Using various media such as steam, hot water, glycol, or hot oil heat tracing is installed to protect the piping, equipment, and instruments against temperatures that would cause congealing or freezing of the process fluids, interfere with operation, or cause damage to the equipment.
Heat Tracing Design Requirements
The daily average low temperature of the coldest month shall be used to select the low ambient design temperature that then determines the degree of winterizing protection required.
No winterizing is required for water service except where a sustained temperature below minus 1 degree C is often recorded for 24 hours or longer.
Compressors, blowers, and other mechanical equipment shall be specified for operation at low ambient design temperatures.
Heat Conservation while Heat tracing
Where feasible, insulation shall be used for heat conservation. Heat tracing, plus insulation, is the alternative method for heat conservation.
Heat transfer cement may be utilized when a process line requires a high heat input and common methods of heat tracing are inadequate.
Steam jacketing is utilized in specific cases where steam tracing with heat transfer cement is inadequate.
Electric tracing is utilized when precise temperature control is required or where steam tracing is not practical. The thermostat setting for electric tracing should not be higher than the fluid operating temperature.
Methods for Winterization
Winterizing by circulation shall be provided where a sufficient power source is available to keep the fluid circulating.
Utility water and utility airlines in intermittent service shall be winterized by draining.
Winterizing by steam tracing is the preferred method when winterizing by circulation and draining is impracticable.
Winterizing by electric tracing is utilized when precise temperature control is required or where steam tracing is not practical. The thermostat setting for electric tracing should not be higher than the fluid operating temperature.
The minimum tracing steam pressure shall be 1 Bar; the maximum required is 10.3 Bar. At minimum pressure, condensate shall be routed to the plant sewer system. If condensate is collected, the minimum usable pressure shall be 1.7 Bar.
Heat Tracer Description
Pipe Tracer Size and Length
Required tracer size shall be determined by piping heat loss and tracer steam pressure found in the Heat Loss Chart (Fig. 1)
The minimum tracer size shall be 3/8 of an inch OD tubing; the maximum size shall be 1 inch OD tubing. For the economy, where Heat Loss Chart indicates the requirements for multiple tracers, a single tracer with heat transfer cement shall be considered.
When using heat transfer cement, tracers of 3/8 of an inch and 1/2 of an inch OD tubing are recommended. If more tracer area is required, multiple tracers of 3/8 of an inch and 1/2 of an inch shall be used.
Maximum tracer length shall be based on tracer size and steam pressure as follows:
Steam pressure 1 Bar through 1.7 Bar
60m for 3/8 of an inch and 1/2 of an inch tracers
100m for 3/4 of an inch and 1-inch tracers
Steam pressure 3.5 Bar through 13.8 Bar
60m for 3/8 of an inch and 1/2 of an inch tracers
120m for 3/4 of an inch and 1-inch tracers
Tracer lengths for Heat tracing with heat transfer cement shall be based on the recommendation of the manufacturer.
For stainless steel lines, the tracer material shall be low-carbon steel. Stainless steel instrument leads shall be traced with copper tubing.
Each tracer shall have its own trap. Tracer traps shall discharge to the sewer. If condensate must be collected, the minimum usable pressure is 1.7 Bar.
Compression-type fittings shall be installed outside of the insulation OD.
Socket-type fittings may be installed inside the insulation.
The steam tracers shall be pressure tested before the insulation is applied. Under emergency conditions, the insulation may be applied but the fittings shall be left exposed until the testing is complete.
Heat Tracer Pocket Depth
Pocket depth is the distance the tracer rises in the direction of flow from a low point to a high point. The total pocket depth is the sum of all risers of the tracer.
The maximum tracer total pocket depth shall be equal to 40 percent of tracing steam gage pressure expressed in meters.
Example: Tracing steam 10.3 bar 30 m x 0.40 = 12 m feet total pocket depth
Tubing used for steam tracing/heat tracing
Steam tracing tubing materials shall be in accordance with material specifications.
Tracers shall be OD tubing. Soft annealed copper tubing shall be used where the temperature of the product line or tracing steam does not exceed 204 °C. Above this temperature, dead-soft annealed hydraulic quality, low carbon, seamless steel tubing shall be used where the temperature of the product line or tracing steam does not exceed 399 °C.
For aluminum pipelines, carbon steel tracer material shall not be used.
For aluminum pipelines and all lines above 399 °C, the tracer material shall be stainless steel.
For conditions where the tracer could overheat lines containing acid, caustic, amine, phenolic water, or other chemicals, insulation spacer blocks shall be installed between the tracer and the pipe.
Fig.4: Typical Heat Loss Chart
Pipe Trunnion or Dummy Support and Their Stress Calculation
Piping Trunnion supports are one of the most frequently used pipe supports in the piping industry. This support is widely used in the piping industry due to its ease of construction and erection. The construction and erection of a pipe trunnion or dummy support are very easy because you have to simply weld a pipe (normally one or more sizes less than the parent pipe to which it is to be welded) with the parent pipe.
A pipe trunnion is defined as an additional pipe of similar or lower size welded to an active piping system to provide physical support. However, trunnion supports with the same size pipe are usually avoided due to profile cutting and welding difficulties during construction.
The load-bearing capacity of trunnion supports is usually less and not as comparable to civil structural supports. So, every pipe stress engineer must check the weld point from a failure viewpoint and investigate the ability to carry the piping load (mostly the tangential and longitudinal load and corresponding moment). The chances of weld failure increase with an increase in trunnion length or trunnion height. Usually, trunnions with a height of more than 1500 mm are not suggested.
Sometimes structural steel members in place of pipe are also added to the parent pipe to form trunnion support. The material of the dummy or trunnion to be attached to the parent pipe should be compatible with the parent pipe material.
Factors affecting load-bearing Capability of Trunnions
The load-carrying capability of a trunnion mainly depends on the following factors:
Parent pipe and trunnion/dummy pipe diameter: With an increase in pipe size the load-carrying capacity increases.
Parent pipe thickness: With an increase in pipe thickness the load-carrying capability increases.
Parent pipe material: With an increase in parent pipe material allowable strength (Sh) the load-carrying capability increases.
Design temperature: With a decrease in design temperature the load-carrying capability increases.
Parent pipe corrosion allowance: With a decrease in corrosion allowance the load-carrying capability increases.
Design pressure: With a decrease in design pressure the load-carrying capability increases.
Trunnion/dummy pipe height: With a decrease in trunnion height the load-carrying capability increases.
Reinforcement Pad thickness at the weld interface: Adding a reinforcement pad at the parent pipe and trunnion pipe increases the load-carrying capability of trunnions to a huge extent. However, adding RF Pads at elbows is difficult to construct and hence suggested to avoid.
Applications of Trunnion or Dummy Supports
Wide application of trunnion or dummy supports is found in control valve assemblies. In control valve stations, trunnion or dummy supports are usually welded from parent pipe elbows as shown in Fig. 1 below:
Fig. 1: Trunnion Supports from Piping Elbow
Trunnion or dummy supports are quite common to use as adjustable supports on a pump or other rotary equipment for alignment purposes.
Typical Trunnion Support Configurations
A variety of support configurations can be made by welding trunnion supports on pipes. Examples of some widely used typical pipe trunnion support configurations are provided in Fig. 2:
Fig. 2: Typical Trunnion Support Configurations
Trunnion Calculation Method
There are various ways in which trunnion checking can be done. However, the Kellogg Method of trunnion checking using an Excel spreadsheet is the most common among EPC organizations. In some organizations, trunnion checking by the WRC method is prevalent. In recent times, Trunnion or dummy support checking using FEA calculations has been increasing among EPC organizations. Various extended modules of stress analysis programs like FE-Pipe/ FE-bend or other FEA programs are used to calculate stresses in the junction point and check if those are acceptable.
In the next paragraphs, I will brief the steps and formulas used while trunnion checking using the Kellogg method.
Inputs Required for Pipe Trunnion Calculation
The inputs that will be required for pipe trunnion calculation are:
Pipe Support loads from stress analysis software.
Parent pipe OD and thickness.
Pipe trunnion OD and thickness.
Parent pipe corrosion allowance.
Parent Pipe material to get stress values.
Pipe design temperature and pressure.
Pipe trunnion height.
RF pad thickness if required/provided.
Steps for Trunnion Calculation by the Kellogg Method
1. First of all run the static analysis in Caesar II/AutoPipe/Rohr II/Start-Prof/Caepipe/Other Pipe Stress Analysis Software to obtain the load values at trunnion nodes from the output processor. It is better to practice taking the maximum value from all load cases (Sustained, operating, design, upset, hydro test, occasional, etc.)
2. After that, calculate the bending stress generated on the pipe shell based on the following Kellogg equation:
Sb=(1.17 * f * √R )/ (t1.5) ……(1)
Here,
Sb=bending stress in pipe shell
R=Outside radius of pipe shell
t=Corroded pipe thickness (actual pipe thickness-corrosion allowance) plus the thickness of reinforcement pad
f=loading per unit length
3. Now from piping stress analysis software, we will get three forces with respect to each trunnion; longitudinal forces, circumferential forces, and axial forces. So accordingly we will have to calculate three f values as mentioned below:
Loading due to longitudinal bending, fL=ML/ (Π r2 ) ……(2)
Loading due to circumferential bending, fC=MC/ (Π r2 ) ……..(3) and
Loading due to axial force, fA=P/ (2Π r)………..(4)
Where,
ML=Longitudinal force obtained from Caesar * trunnion effective length
MC=Circumferential force obtained from Caesar output * trunnion effective length
P=direct axial force obtained from Caesar II output. and r=outside radius of the trunnion.
4. Next step is to calculate all bending stresses using equation (1) for longitudinal (SL), axial (SA), and circumferential (SC) forces as calculated from equations (2), (3), and (4).
5. Now Calculate longitudinal Pressure Stress (SLP=PD/4t) and Hoop Stress (SCP=PD/2t).
6. In the next step, combine all these forces for proper load cases as shown below and compare the combined value with the allowable stress value provided in terms of the Sh and Sc values as defined in the ASME B31.3 code.
SL+ SA + SLP <= k * Sh
SC+ SA + SCP <= k*Sh And
Trunnion Stress<=Sh
Here trunnion stresses should be calculated as=[{32*Trunnion OD*√(ML2+MC2)} / {Π*(Trunnion OD4-Trunnion ID4)}]
The values of “k” are dependent on loading types. The allowable stress values as suggested in the Kellogg Method are produced below in Fig. 3 for reference.
Fig. 3: Allowable Stress Values for Trunnion Calculation as per Kellogg Method
Options to reduce stresses while Trunnion Support Checking
There are various ways by which the calculated stresses on the trunnions can be reduced so that the dummy calculation qualifies with respect to allowable stresses. Some of such tips are
While checking trunnions or dummies, it is found that a major chunk of trunnion supports fails due to circumferential loads. So, orient or place the trunnion in such a way that the circumferential force on the trunnion becomes very less to permit/allow greater trunnion heights.
Reducing the trunnion height or increasing the trunnion size also will reduce the calculated stresses.
RF pads are required to be added to increase the junction thickness and thereby increase load-carrying capabilities which decrease stresses.
Increasing the parent pipe diameter will also qualify the trunnions. However, increasing parent pipe size needs process confirmation.
What is the difference between a Trunnion and a Dummy Leg?
Even though the terms “Trunnion” and “Dummy Leg” are used interchangeably, there is a slight difference between the two pipe supports.
Dummy pipe is welded onto the pipe elbow to extend the line to reach the next support while Pipe trunnions are welded to vertical lines. Usually, two short pipe pieces are welded to vertical pipe for better stability for trunnion application. It’s easier to provide an RF pad on trunnion supports but the same is difficult for dummy legs as the pipe profiling and welding at pipe elbows are usually difficult.
Online Course on Pipe Support Engineering
If you want to learn more details about pipe support engineering then the following online course is a must for you:
Conductivity is the ability of a material to transfer an electric charge from one point to another. To transfer current, charged particles must be present in the solution. It is a standard practice to measure conductivity in aqueous solutions as different salts, acids, and bases dissolved in water act as electrolytes and provides ions. How well a solution conducts electricity is measured by the term conductivity. Ohm’s Law provides the basic idea of Conductivity.
E = I • R where E = applied voltage between two “plates” I= electrical current R=Resistance of the conductor.
From the above equation, conductivity can be defined as the reciprocal of resistance of a solution between two electrodes and it is expressed as:
G = I/R
The units used for conductivity are Mhos or more commonly used Siemens. Mhos and Siemens can be used interchangeably.
However, to compensate for variations in the electrode dimensions, standardized measurements are expressed in specific conductivity units. By multiplying the measured conductivity (G) as mentioned above by the electrode’s cell constant (L/A); Specific conductivity is calculated. Hence, Specific conductivity (C) is given by
C = G x (L/A) where L=the length of the liquid column between the electrodes A= area of the electrodes
Conductivity meters use this equation to calculate the conductivity of a solution and display the results.
Resistance is the inverse of conductance. Materials that are in the liquid phase and conduct electrical current are called electrolytes.
Application of Conductivity Measurement
Conductivity measurement is widely used for quality control purposes. For monitoring and controlling of used water, conductivity is one of the important, cost-effective, and stable parameters. That is the reason conductivity measurement has found numerous industrial applications. The major areas where conductivity is important are listed below:
Treatment of Water Quality
RO systems; Conductivity measurement of pure water.
Desalination industry.
Boiler feedwater protection.
Water towers.
Hardness protection in laundries.
Salinity Testing.
Condensate and Steam quality protection.
Wastewater treatment.
TDS Testing.
Concentration measurements and control
Finding the concentration of various acids like Hydrochloric acid, Phosphate, Ammonium and ammonia gas, Nitric acid, Sulphuric Acid, etc.
Conductivity measurement can also be helpful in analyzing Carbon dioxide and Sulphuric dioxide in water.
Refer to the following figure (Fig. 1) that lists all the applications of conductivity measurements.
Fig. 1: Applications of Conductivity Measurement
Measurement of Conductivity
The devices that are used to measure conductivity are called Conductivity Analyzers or Conductivity meters. There are two ways in which the conductivity in liquids or slurries is measured:
Contacting (or Electrode) Measurement.
Toroidal (Inductive or Electrodeless) Measurement.
Fig. 2: Conductivity of familiar solutions
Contacting or Electrode Type Measurement (Fig. 3):
The two-electrode methodology uses two opposing electrodes.
The anode is supplied with a known current, which is picked up by the cathode when placed in an electrolyte.
The amount of current picked up by the cathode is dependent upon the conductance of the electrolyte.
Probe/Cell Constant of Conductivity Meter:
The cell constant is the distance between the electrodes divided by the area of the electrodes.
K (cm-1) = Distance between electrodes (cm) / Area of electrodes (cm)
The smaller the cell constant the higher the signal that will be returned to the meter.
Low conductivity solutions use a small cell constant and high conductivity solutions will use a larger cell constant sensor.
Two Electrode Methodology:
Its main drawback is:-
The sensor is susceptible to coating and corrosion, which drastically lowers the reading.
In strongly conductive solutions there can also be polarization effects, which results in non-linearity of the measurement.
The Four Electrode Methodology for Conductivity measurement:
It utilizes the same two-electrode measuring scheme, but it also includes an additional two-electrode system to act as a reference point for the measuring circuit, for use in applications where light coats from the process can occur.
The minimum range for this type of electrode is approximately 5000 micro S/cm.
Fig. 3: Contracting and Toroidal Measurement
Toroidal Type Measurement (Fig. 3):
Toroidal conductivity measurement is made by passing an AC current through a Toroidal drive coil, which induces a current in the electrolyte solution.
This induced solution current, in turn, induces a current in a second toroidal coil, called the pick-up toroid.
The amount of current induced in the pick-up toroid is proportional to the solution conductivity.
Advantages of Toroidal Type Conductivity:
The toroidal coils are not in contact with the solution.
The insertion-style Toroidal sensor can be completely coated by a solid OR oily contaminant in the process, with essentially NO lowering of the reading until the coating displaces a significant volume of the surrounding liquid.
The polymeric material housing the Toroids can be chosen to be compatible with corrosive solutions,
Drawbacks of Toroidal Type Conductivity Measurement :
It lacks the sensitivity of contacting measurement.
Toroidal sensors are also typically larger than contact sensors, and the solution current induced by the Toroid occupies a volume around the sensor. Hence, Toroidal sensors need to be mounted in a larger pipe.
Temperature Effects on Conductivity Measurement
Temperature does have a significant effect on the conductivity of solutions.
The same solution concentration at different temperatures has a drastically different conductivity.
In order to measure the conductivity temperature effect must be compensated.
For Temperature, compensation follows the steps shown in Fig. 4
The temperature coefficients of the following electrolytes generally fall in the ranges shown below:
Acids 0 – 1.6%/°C
Bases 8 – 2.2%/°C
Salts 2 – 3.0%/°C
Freshwater 0%/°C
Fig. 4: Temperature Effects on Conductivity Measurement
Calibration of Conductivity Analyzers
Moderate to High Range Measurements:
For conductivity measurements in excess of 100 μS/cm, a conductivity standard may be used to calibrate a conductivity loop.
The conductivity measurement may also be calibrated using grab sample standardization.
Care must be taken that the correct temperature coefficient is being used in both the online instrument and the referee instrument to avoid discrepancies based on temperature compensation errors.
High Purity Water Measurements
Conductivity samples below 100 μS/cm are highly susceptible to contamination by trace contaminants in containers and by CO2 in the air. As a result, calibration with a conventional standard is not advisable.
Many conductivity instruments designed for high-purity water measurements include a calibration routine for entering the constant of the conductivity sensor.
The conductivity sensor used with this kind of instrument must have its sensor constant accurately measured using a conductivity standard in a higher range. Once the sensor constant is entered into the instrument, the conductivity loop is calibrated.
A second method is to calibrate the online instrument to a suitably calibrated, reference instrument in a closed flow loop.
