Boostrand ChemE

What is the height that you shall consider when calculating the available pump NPSH?

1 week ago | [YT] | 14

Boostrand ChemE

When we prepare P&IDs to include pump startup considerations, we should consider the below:

- Suction strainer: catches debris during initial runs
- Differential pressure across the strainer: tells you when debris is causing a significant drop
- If ∆P rises, stop the pump, clean the strainer, restart, and repeat until ∆P stabilizes
- Discharge pressure gauge: monitor while throttling the discharge valve to land on the pump curve

Here the P&ID is designed from the operator’s perspective—so startup is predictable, trips are fewer, and maintenance is planned, not reactive.

If you want a deeper walkthrough of pump-related P&ID considerations, you can check out the below article:

boostrand.com/discover-tips-for-preparation-of-a-p…

1 month ago | [YT] | 3

Boostrand ChemE

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1 month ago | [YT] | 3

Boostrand ChemE

The #1 Mistake That Kills Process Design Projects Before They Start

We've all been there. The simulation looks perfect. The software runs smoothly. Then the plant starts up and... nothing works as designed.

Why? Because we forgot the golden rule: Garbage in, garbage out.
Process simulation software like Aspen HYSYS, Aspen Plus, or PRO/II are powerful tools. But they're only as good as the data we feed them.

Here are examples of what can happen with wrong input data:

🔴 Wrong separator composition input leads to:
• Incorrect vapor fraction
• Wrong liquid/vapor flow rates
• Improperly sized equipment
• Pumps and compressors designed for unrealistic conditions
• Complete operational failure

🔴 Missing operating scenarios:
• Design for light hydrocarbons only
• Heavy hydrocarbons show up unexpectedly as a dominant case
• Equipment can't handle the variation
• Lots in modifications required

The solution? Don't treat process simulation as an isolated activity. It must be grounded in:
✓ Solid engineering principles
✓ Understanding of downstream impacts
✓ Clear design basis documentation and proper agreement with client or other stakeholders

Remember: Your client-approved design basis isn't just paperwork—it's your protection when issues arise.

If you'd like to understand more about process engineering activities, you can check out the below link:
boostrand.com/the-fundamentals-of-process-design-a…

Now what was your worst "bad input data" story? I hope you share in the comments below.

#ProcessEngineering #ChemicalEngineering #ProcessDesign #ProcessSimulation #EngineeringExcellence #AspenHYSYS #ProcessSafety #EngineeringLessons

1 month ago | [YT] | 7

Boostrand ChemE

U tube shell and tube exchangers are very common to use in industry. So when are they used? Let’s break down their main advantages and disadvantages:

🔧 Cleaning: Shell vs. Tube Side

One of the key features of a U-tube heat exchanger is that the **tube bundle is removable**, which allows for mechanical cleaning of the shell side. This is particularly useful in applications where fouling is expected on the shell side and regular maintenance is required to ensure optimal performance.

However, it's important to note that while the shell side can be cleaned easily, this is not the case for the tube side.

Due to the U-bend shape, only the outermost tubes can be cleaned mechanically. This makes U-tube exchangers less suitable for applications where frequent or thorough cleaning of the tube interiors is necessary.

That's why in reboilers we use U tube when heating with steam in the tube side as cleaning is not a concern. However, if we use a fouling fluid as a heating medium, we avoid the use of U tube bundle in this case.

💡Cost and Compact Design

When it comes to cost, U-tube exchangers can be more economical compared to other heat exchanger designs, such as floating head exchangers. The main reason for this is the use of only one tubesheet, which reduces material and fabrication costs.

However, it's worth noting that the bending of the tubes and the need for a larger shell diameter to accommodate the U-bend radius can offset some of the cost savings, bringing the overall cost closer to that of a fixed-tubesheet exchanger.

Despite this, U-tube exchangers still offer a relatively compact design that can be beneficial in situations where space is limited. Their ability to handle a wide range of applications while maintaining a smaller footprint compared to other designs makes them a strong contender for tight spaces.

🔥Thermal Expansion

One of the most significant advantages of U-tube heat exchangers is their ability to handle differential thermal expansion. Since one end of the tube bundle is free to expand or contract, U-tube exchangers are particularly suited for applications where there are large temperature differences between the shell and tube sides.

This design flexibility helps mitigate thermal stresses, making U-tube exchangers ideal for high-temperature applications or processes where temperature fluctuations are common.

Conclusion

To summarize, U-tube heat exchangers are an excellent choice when you need a removable bundle for easy shell-side cleaning, particularly in processes with significant thermal expansion considerations. Although the tube interiors can be difficult to clean, the lower initial cost and compact design make them a practical solution for many applications.

However, if your process involves dirty fluids inside the tubes or requires frequent internal tube cleaning, you may want to consider alternative designs like floating head exchangers.
If you'd like to explore different exchanger TEMA types and the factors affecting their selection, you can check out our video (Choosing the proper Exchanger TEMA type) in the below link:📺
boostrand.com/how-to-choose-the-optimum-exchanger-…

2 months ago | [YT] | 4

Boostrand ChemE

When carrying out any engineering project, the project schedule always reserves a place for safety studies. This is because they play a critical role in ensuring that the expected hazards are identified and dealt with in the design.

So how safety studies are typically executed in a project? Think of it as a pyramid, moving from broad to specific:

Pyramid of Process Safety Studies

1️⃣ Level 1: HAZID (Hazard Identification)

When: Conceptual Design Phase. This is your earliest look at what could go wrong.

Why: It identifies major hazards when design changes are cheapest, allowing you to incorporate inherently safer designs from the start. Early studies like this make later, more detailed studies like HAZOP easier and faster.

Example: Realizing a proposed chemical storage tank is too close to a critical control room and relocating it on the plot plan.

2️⃣ Level 2: HAZOP (Hazard and Operability Study)

When: FEED and Detailed Engineering Phase, with mature P&IDs.

Why: It's a systematic deep-dive into your design, challenging every part to find potential deviations (e.g., "No Flow," "More Pressure") and ensuring safeguards are adequate.

Example: A HAZOP on a reactor feed line identifies a scenario where a valve could fail closed, dead-heading a pump. The team recommends adding a high-pressure trip to shut down the pump.

3️⃣ Level 3: LOPA (Layer of Protection Analysis)

When: Immediately after HAZOP for high-risk scenarios.

Why: It provides a semi-quantitative check to see if your existing safeguards (or "layers") are strong enough. If not, it tells you how much more risk reduction you need.

Example: LOPA shows that an operator responding to an alarm isn't a reliable enough safeguard for a runaway reaction scenario. It calculates that a 100-fold risk reduction is needed, triggering the requirement for an automated safety function.

4️⃣ Level 4: QRA (Quantitative Risk Assessment)

When: On a need-basis only.

Why: This is a highly detailed analysis for the highest-consequence scenarios (e.g., explosions, toxic releases) flagged by HAZOP/LOPA or required by regulators. It provides a full quantitative picture of the risk.

Example: Modeling the potential impact of a toxic gas release to verify that emergency response plans and plant layout are adequate to protect workers and the public.

💡 Why the Sequence Matters?

Starting HAZID too late means missing basic safety outcomes which can lead to a large impact. Starting HAZOP too early leads to guesswork. Waiting on a necessary QRA can halt a project. Getting the timing right saves months of delays and ensures you meet your regulatory and corporate responsibilities.

Want to know more about project phases? You can check out this article:
boostrand.com/understand-process-design-stages-fro…

#ProcessSafety #Engineering #ProjectManagement #RiskManagement #HAZOP #LOPA #QRA #ChemicalEngineering #SafetyFirst

2 months ago | [YT] | 9

Boostrand ChemE

🚀 Tower Tray Selection for Fouling Services – Quick Guide! 🚀

Struggling with fouling, polymerization, or dirty services in your distillation columns? The wrong tray choice can lead to costly shutdowns. Here’s a quick breakdown of the best options:

✔ For Clean to Moderate Fouling:

💠 Valve Trays

Fixed valves: Good fouling resistance with horizontal vapor discharge that prevents stagnant zones. Best for moderate fouling with decent turndown.

Movable valves: Excellent efficiency and turndown, but moving parts can stick in fouling services. Avoid for polymerizing fluids.

💠 Sieve Trays

Simple and economical. Can handle moderate fouling with large holes (3/4" to 1"). Not suitable for severe fouling or wide turndown requirements.

💠 Bubble Cap Trays

Elevated risers resist some fouling. Excellent for low flow rates. However, stagnant areas under caps make them poor for polymerizing services.

✔For Severe Fouling:

💥 Dual Flow Trays

The gold standard for severe fouling. No downcomers = no stagnant zones. Self-cleaning action from competing vapor-liquid flow. Lower efficiency but unmatched reliability for dirty services.

💪 Baffle Trays

For the worst cases (heavy solids, slurries). Very open design resists plugging. Low efficiency but keeps running when others fail.

Packed Towers?

❌ Generally avoid for fouling services

Structured packing plugs easily

Random packing (large size) handles light fouling

Grid packing works for severe fouling but requires proper liquid distribution


Key Takeaway: In fouling services, reliability beats efficiency—choose a tray that runs, not one that clogs!


Need to know more about tower operation? Check out the below link! 🔧

boostrand.com/discover-basic-guidelines-for-an-eff…

#ProcessEngineering #Distillation #FoulingSolutions

2 months ago (edited) | [YT] | 7

Boostrand ChemE

When it comes to treating water contaminated with hydrocarbons, selecting the right separation technology is crucial for both environmental compliance and operational efficiency. Two commonly used technologies are API (American Petroleum Institute) separators and CPI (Corrugated Plate Interceptors) separators. Understanding the differences between them and knowing when to use each can significantly impact your facility's performance and environmental footprint.

API Separators:

Traditional gravity-based settling tanks that remove free oil from water. They are cost-effective, simple to maintain, and suitable for primary treatment onshore applications with ample space.

CPI Separators:

Compact designs with tilted plate packs that enhance separation efficiency. They are ideal for space-constrained environments, including offshore platforms.

Key Performance Differences

Footprint and Location: API separators are large and bulky, suitable only for onshore applications where space is abundant. CPI separators offer a compact design that works both offshore and onshore, making them ideal for space-constrained environments.


Oil Removal Efficiency: While API separators remove oil droplets down to 150 microns, CPI separators achieve finer separation, capturing droplets as small as 60 microns. This translates to better effluent quality from CPI systems. If you'd like to understand more about separation performance criteria, you can check out the article How Two Phase and Three Phase Separators Work?.


Solids Handling: API separators handle high solids content better due to their simple design. CPI separators may require an upstream settling tank when dealing with high solids content to prevent fouling of the plate packs.


Application-Specific Selection

API: Primary treatment for high-oil-content wastewaters where space is available.

CPI: Applications requiring high efficiency, compact footprint, and minimal maintenance.

Sometimes we may use a combination, API for primary treatment to remove most oil and sediments, then CPI is used to even enhance the separation efficiency.

It all depends on the required separation regulations and the downstream unit receiving the treated water.


Conclusion

Choosing between API and CPI separators involves evaluating performance requirements, space constraints, economic factors, and operational considerations. Understanding these differences will help you make informed decisions for your water treatment needs.

If you like to discover more about the separator sizing and performance criteria, you can check out the article below:
boostrand.com/how-two-phase-and-three-phase-separa…

3 months ago (edited) | [YT] | 15

Boostrand ChemE

We've talked about why we need check valves on pump discharge, but here's what can go wrong if you place them in the wrong position. This can be found in the below link:
youtube.com/shorts/Ha997jKYDBI

The Critical Placement Decision 🎯

When installing a check valve UPSTREAM of the discharge isolation valve (between pump and isolation valve), you're making a strategic choice that impacts:

⚠️ Maintenance Efficiency
If your check valve needs repair or replacement, you can isolate just that section without affecting the entire system. Placing it downstream would require shutting down larger portions of your system or even draining tanks.

⚠️ Equipment Protection
The check valve immediately protects your pump from reverse flow and potential water hammer damage - especially critical in multi-pump systems where one pump might shut down while others continue operating. In case of compressors, it's even more critical.

⚠️ Proper Isolation
During pump maintenance, having the isolation valve downstream means you can work on the pump without pressurized fluid in your work area.

The Reality Check on Check Valves ⚡

Here's the scary part: check valves can fail silently. Since they only close when backflow occurs, a stuck-open valve might go unnoticed for months—until the one moment you desperately need it.

Why are they prone to failure?
• Constant movement = wear on seats and seals
• Debris sensitivity prevents proper sealing
• Can't provide true positive isolation like manual valves

That's why we place isolation valves downstream of the check valve—when the isolation valve is closed, it reduces backflow incidents, making the check valve a second line of defense rather than the sole protection.

API 521 Best Practices 📋
For critical applications:
• Install double check valves in series
• Use different valve types (e.g., piston + spring-loaded split wedge)
• Implement firm inspection procedures
• Consider additional protection layers for high-consequence scenarios

Remember: proper valve arrangement isn't just about following standards—it's about understanding the "why" behind each decision.

What valve arrangement challenges have you faced in your systems? Share your experiences below! 👇

#ProcessSafety #MechanicalEngineering #PumpMaintenance #IndustrialSafety #CheckValves #API521 #ProcessEngineering #MaintenanceBestPractices

3 months ago | [YT] | 8

Boostrand ChemE

In any plant, you'll find numerous Pressure Safety Valves (PSVs) that protect equipment from overpressure. But have you ever wondered how the flare system handles the maximum relief load from all these PSVs combined? 🤔

That's where the process engineer comes in! 👷‍♀️ It's their responsibility to carry out a thorough flare system check and ensure that the maximum relief load is accurately evaluated. This involves considering various relief scenarios and common cause failures that could lead to simultaneous relief loads from multiple PSVs.

The process engineer will typically summarize their findings in a relief load summary, which serves as a key document for designing and sizing the flare system components. This summary takes into account factors like relief conditions, flare radiation, and potential mitigations to optimize the flare design.

By carefully analyzing the relief loads and their timing, the process engineer can determine the peak combined load that the flare system must handle. This ensures that the flare system, including the flare tip, knockout drum, and headers, is adequately sized to safely dispose of the maximum relief load.

If you'd like to know more about process documents issued by a process engineer, you can check out this link:

boostrand.com/the-fundamentals-of-process-design-a…

3 months ago (edited) | [YT] | 8