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Distillation

Distillation

Well, this is an endeavor to present a detailed study that highlights the importance and significance of the distillation process .we intend to draw your attention towards the fact that its significance can never be undermined.

This guide certainly throws light upon Distillation process, control and trouble shooting .More emphasis should be put upon doing regular inspection and what it takes to work seamlessly .It decontaminates any chemical substances

And further makes it super pure as per the necessities. In addition to this the entire function is more driven by the process that changes the fluid into vapor and the vapor into fluid. Therefore things being what they are-what makes it working everlastingly to inspect the complete process, so it works the best and for your industry pre-requisite there are couple of things to be taken account of.

Distillation is taken into account for various commercial processes. For instance .in creation of fuel, refined water, xylen , liquor, paraffin, lamp oil and numerous other fuels. With that gas can be melted and further discrete. Lets say Nitrogen Oxygen and argon are mostly refined from air itself. Moreover, in order to corporate distillation processes, they are mostly basic distillation, fragmentary distillation and destructive distillation. Regular inspection is mandatory in order to keep it going. Critical situation arises and becomes tough to manage when operators and engineers overlook and disregard the functioning of distillation.

Distillation Operation- The fluid bend prepared is known as the feed. Distillation control-As Distillation process triggers 95% of the separation process to the fullest potential. Many industries rely on chemical processes require distillation at an alarming rate .Thus it can be well asserted that Distillation Operations legitimately influence Item quality ,process creation rates and utility use by far. Hence the monetary significance of distillation should not be ignored and its thorough inspection is much needed. What makes it an arduous task is the procedure Non-linearity, Multivariable coupling, serious unsettling influences and Non stationary conduct in the long run.

Distillation troubleshooting- It is imperative to make use of essential tool to comprehend the temperature weight and steam in the Distillation Column. Failure to do so certainly becomes a huge issue.

Comprehend the weight balance- to understand the operation of a distillation column weight inclination between stages should be examined. It should function seamlessly.

Thus realizing the significance of distillation tube control and check needs to be put on for the success of the processing plant. Hence if the above measures are taken you are sure to succeed and experience vitality cost down and benefit up’s


Reformer Tube

Reformer Tube

INTRODUCTION

When we talk about Reformer Tube the first thing that strikes our mind is how can a tube life be maximized and secondly what measures need to be taken if a tube fails. Needless to mention, that, the reformer tube is the most significant and exorbitant component of the plant. Its replacement is certainly very expensive.

Design of Reformer Tube

It is in accordance with known international standards, typically following the guidelines given in API530 for a designed creep life for the selected material. Laboratory short–term test is executed to derive the minimum required wall thickness for tube to combat the creep. Time to rupture is assessed for a range of temperature and stress.

Metallurgical development

Wrought alloy steels are burgeoning. Historically, a HK40 material was utilized for the last 40 years. However, the HP modified grade of steels which are micro-alloyed with the addition of zirconium, titanium tungsten and other rare earth elements is within easy reach that substantially increased the creep life. It is more expensive when compared to HK40. However thinner tubes should be opted for as it provides longer life, high heat transfer efficiency and with the same price yield.

Failure Mechanism

An increase in diameter is generally observed as a result of creep strain due to prolonged serviAn increase in diameter is generally observed as a result of creep strain due to prolonged service at elevated temperature and internal stress. This eventually culminates in rupture. This is certainly a dominant damage Mechanism and it is life limitingce at elevated temperature and internal stress. This eventually culminates in rupture. This is certainly a dominant damage Mechanism and it is life limiting.

Another factor that accelerates normal “end to life” is over-firing or Flame impingement. Besides thermal cycling is also responsible for “end of life”.

Life assessment methods

Routine skin temperature measurements that are ought to be taken. The data forms a guideline for life fraction consumption calculations.

Ulrasonic Attenuation- It is obviously an excellent principle for detection of mid-wall fissures. It is often found difficult to calibrate unless references with similar creep damaged tubes are made available. Ultrasound passing in through mode transmission mode will get attenuated due to creep voids and almost blocked when there are fissures (micro cracks) in the sound path. The ultrasound attenuation method is the best detection tool by NDT. Scaffolding is not required here if automation is used to crawl up and down on the tubes. The suspected tubes identified to have creep fissures by ultrasound method are often offered for a follow up NDT inspection method of Radiography.

Radiography- Radiology is usually done in suspected areas to image the creep fissures. It is primarily advantageous to confirm the presence of mid-wall cracks. It takes up much of the time and restricts the work area due to radioactivity during time of testing and hence it is often limited to sampling – generally based on ultrasound attenuation results.

Microstructural examination – Although, the creep voids and fissure formation starts from mid-wall, their incubation and initiation periods are dependent on metallurgical condition of the material. The microstructural examination is an excellent tool to judge the metallurgical condition. The coalesced carbides, grown up secondary carbides, absence of secondary carbides with blocky primary ones are all indicators of metallurgical aging of the tube at different stages. An active feedback of the metallurgical condition with creep strain data provides more accurate prediction of remaining life.

Hammering the final nail, it can be stated that tube life can be maximized by properly analyzing different measurements of tube condition - that typically involve – diameter measurements throughout the length of tube, wall thickness measurements, metallurgical ageing and detection of internal creep fissures.

Tube Metallurgy has reached a plateau as there is nothing new on the Horizon. Future enhancements are more likely to be in smart coatings to improve Heat transfer.


Corrosion Under Insulation

corrosion under insulation

CUI takes place under insulating material in the oil & gas, chemical, and food processing industries, to name but a few industries affected, costs millions of dollars on a yearly basis. In this article, the major factors that lead to corrosion under insulation are examined and the major types of units and equipment that get affected are discussed. CUI appearance is also discussed. Further, an important section of the article looks at how corrosion under insulating materials can be prevented, as well as preventive inspection and monitoring practices, including the use of a probe array sensor inserted to detect its formation at thermally insulated pipeline field joints.

Introduction

The corrosion that takes place under insulation material is a major problem. It has been a primary problem in the oil & gas, chemical, food processing, and other industries for many years and has cost many millions of dollars in inspection and repair of process pipes and pipelines. The American Petroleum Institute code, API 570 Inspection, Repair Alteration and Re-rating of In-service Piping Systems, (June 1993), identifies Corrosion Under Insulation (CUI) as a special concern. In 2003, the European Corrosion Federation reported that most leaks in the refining and chemical industries were due to CUI, rather than process leaks. When insulation material becomes wet (because of poor installation practices, subsequent abuse or failure to specify good vapor barriers and waterproofing materials), it “creates the potential for corrosive failure of the piping”. Whether pipes are above ground or buried, proper design and installation techniques can control corrosion. CUI is one of the predominant mechanical integrity issues affecting the ethylene industry. Occurrence can be erratic and sometimes undetectable based on visual examination. In addition to these recognized problem areas, it is also important to look for areas that are susceptible to CUI due to swing conditions or non-flow areas, even though the design and observed operating condition of the line fall outside this range.

It results from the collection of water in the vapor space (or annulus space) between the insulation and the metal surface. Sources of water may include rain, water leaks, condensation, cooling water tower drift, deluge systems, and steam tracing leaks. CUI causes wall loss in the form of localized corrosion. Plants located in areas with high annual rainfall or warm, marine locations are more prone to CUI than plants located in cooler, drier, mid-continent locations. Units which are located near cooling towers and steam vents are highly susceptible to CUI, as are units whose operating temperature cycle through the dew point on a regular basis. The external inspection of insulated systems should include a review of the integrity of the insulation system for conditions that could lead to CUI and for signs of ongoing CUI, i.e. rust stains or bulging.

Prevention of CUI can be carried out through proper coating and good insulation practices. Good installation and maintenance of insulation prevents ingress of large quantities of water. A coating system is frequently specified for component operating in the CUI temperature range, and where CUI has been a problem. A good coating system should last a minimum of fifteen years. Currently there are few reliable inspection and monitoring techniques and so new sensors for CUI inspection.

Major factors which affect CUI
  • It affects externally insulated piping and equipment and those that are in intermittent service or operate between –12°C to 175°C for carbon and low alloy steels whereas 60°C to 205°C for austenitic stainless steels and duplex stainless steels.

Corrosion rates increase with increasing metal temperature up to the point where the water evaporates quickly. For insulated components, corrosion becomes more severe at metal temperatures between the boiling point 100°C and 121°C, where water is less likely to vaporize and insulation stays wet longer.

  • 1. Design of insulation system, insulation type, temperature and environment are critical factors.
  • 2. Design of insulation system, insulation type, temperature and environment are critical factors.
  • 3. Insulating materials that hold moisture (wick) can be more of a problem.
  • 4. Cyclic thermal operation or intermittent service can increase corrosion.
  • 5. Equipment that operates below the water dew point tends to condense water on the metal surface thus providing a wet environment and increasing the risk of corrosion.
  • 6. Damage is aggravated by contaminants that may be leached out of the insulation, such as chlorides.
  • 7. Plants located in areas with high annual rainfall or warmer, marine locations are more prone to CUI than plants located in cooler, drier, mid-continent locations.
  • 8. Environments that provide airborne contaminants such as chlorides (marine environments, cooling tower drift) or SO2 (stack emissions) can accelerate corrosion.
Units or equipment which get affected by CUI
  • 1. Insulated equipment and piping are susceptible to CUI under conditions noted above even on piping and equipment where the insulation system appears to be in good condition and no visual signs of corrosion are present.
  • 2. CUI can be found on equipment with damaged insulation, vapor barriers, weather proofing or mastic, or protrusions through the insulation or at insulation termination points such as flanges.
  • 3. Equipment designed with insulation support rings welded directly to the vessel wall (no standoff); particularly around ladder and platform clips, and lifting lugs, nozzles and stiffener rings.
  • 4. Piping or equipment with damaged/leaking steam tracing.
  • 5. Localized damage at paint and/or coating systems.
  • 6. Locations where moisture/water will naturally collect (gravity drainage) before evaporating (insulation support rings on vertical equipment) and improperly terminated fireproofing.
  • 7. Vibrating piping systems that have a tendency to inflict damage to insulation jacketing providing a path for water ingress.
  • 8. Deadlegs
  • 9. Steam tracer tubing penetrations.
  • 10. Caulking that has hardened, has separated, or is missing.
  • 11. Bulges or staining of the insulation or jacketing system or missing bands.
  • 12. Low points in piping systems that have a known breach in the insulation system, including low points in long unsupported piping runs.
  • 13. Carbon or low-alloy steel flanges, bolting, and other components under insulation in high-alloy piping systems.
  • 14. Locations where insulation plugs have been removed to permit piping thickness measurements on insulated piping and equipment should receive particular attention.
CUI appearance
  • 1. Majority of construction materials used in plants are susceptible to CUI degradation, mitigation is best achieved by using appropriate paints /coatings and maintaining the insulation /sealing / vapor barriers to prevent moisture ingress.
  • 2. Flame-sprayed aluminium coatings have been used on carbon steels. The coating corrodes preferentially by galvanic action, thereby protecting the base metal.
  • 3. High quality non-metallic coatings, properly applied to the surfaces to be insulated can provide long term protection.
  • 4. Thin aluminium foil wrapped on stainless steel piping and equipment has been used on stainless steels as an effective barrier under insulation.
  • 5. Careful selection of insulating materials is important. Closed-cell foam glass materials will hold less water against the vessel / pipe wall than mineral wool and potentially be less corrosive.
  • 6. Low chloride insulation should be used on 300 Series SS to minimize the potential for pitting and chloride SCC.
  • 7. It is not usually possible to modify operating conditions. However, consideration should be given to removing the insulation on equipment where heat conservation is not as important.
CUI inspection and monitoring
  • 1. An inspection plan for corrosion under insulation should be a structured and systematic approach starting with prediction/analysis, then looking at the more invasive procedures. The inspection plan should consider operating temperature; type and age/condition of coating; and type and age/condition of insulation material. Additional prioritization can be added from a physical inspection of the equipment, looking for evidence of insulation, mastic and/or sealant damage, signs of water penetration and rust in gravity drain areas around the equipment.
  • 2. Although external insulation may appear to be in good condition, CUI damage may still be occurring. CUI inspection may require removal of some or all insulation. If external coverings are in good condition and there is no reason to suspect damage behind them, it may not be necessary to remove them for inspection of the vessel.
  • 3. Considerations for insulation removal include history of CUI for the vessel or comparable equipment, visual condition of the external covering and insulation, evidence of fluid leakage, e.g. stains, equipment in intermittent service, condition/age of the external coating.
  • 4. Common areas of concern in process units are high moisture areas such as those down-winds from cooling towers, near steam vents, deluge systems, acid vapour’s, or near supplemental cooling with water spray.
Inserted probe array sensor for CUI monitoring

The Inserted Probe Array Sensor acts as a ‘corrosion fuse’ detector that will provide an indication of corrosion occurring at the pipe surface, at known discrete locations. It was originally designed to be installed during the remediation and mitigation of corrosion damage under thermally insulated pipeline field joints. There are two common types of pipeline insulation repair processes. The first requires the old cladding to be removed with the insulation left in place. Insulation tape is wrapped around the affected area and a new protective cladding is strapped in place. The second involves removing an entire section of insulation from a damaged area. The pipe is repaired and cleaned, and new insulation is installed. Insulating tape is then applied and a protective outer cladding is strapped in place.

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