Mihail Editoiu profile | Linquip

Mihail Editoiu

Linquip Level: Advanced

Prahova, Romania

Lead process engineer at pureworld

Bsc in chemical engineering

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About:

Experience in process design including fesability studies, conceptual design, basic design, FEED, detailed design, optimization, "What-if" studies/activities and Digital Twin. Refinery/Petrochemical units licensor selection - pro's & con's, midstream NGL recovery plants and impurities removal units plus dehydration and BTX/aromatic removal technology selection - advantages/disadvantages. Crude & Vacuum unit design/retrofit/optimization expert and Aromatic Complex. Advance depressurization study to proper select MOC and to minimize flare loads.

Expertise:

Digital Twin

Rigorous depressurization

Refinery licensor selection

Process simulation

Troubleshooting and problem solving

Activities:

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Ionic Alkylation: Petrochina at pilot Plant level & Uop with Isoalky - Uop & Chevron test 4 years a pilot Plant & want to convert HF unit to Isoalky. Sinochem shall build an Isoalky unit under Uop licence. Conversion of HF to H2SO4 could be 4500 $/ BPD.

ME

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Alkylation unit. HF units, Even a lot all over the WORLD need to be converted to new / proven tech. Conventional Players: Stratco part of DuPont with well proven H2SO4, Exxon & Lummus. Stratco with Shell&tube HX with impeller and circulating tube reactor with acid emulsion, 4 barg reactor pressure & 4-10 C, indirect refrigeration & iC4/olefin ratio 8:1 or higher. Exxon the same T as Stratco, with Multiple CSTRs in series - acid emulsion, reaction p 0.8-1 barg, auto refrigeration 8:1 ratio. CDAlky with vertical reactor & proprietary mix device, auto refrigeration & minor items to be revamped in case of HF to H2SO4 conversion. All mentioned units provide 1.8 bbl/bbl olefin. Solid catalyst: KBR, CB&I, Uop. Unfortunatelly Uop without industrial experience, K-saat & Alkyclean with 1st unit in operation, but K-saat is on the wave with lower CAPEX, higher RON, lower RVP, no noble catalyst, free ASO & higher cycle time that competitors (25 times longer), much safer than classical H2SO4plant.

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Downstream. SWS Unit: very simple process but without it the Refinery could not work. Simulation Tips: use 10–15 theoretical trays, top temperature in KO drum min 85C to avoid salts deposits, operating pressure as close as possible to atm, use reboiled column not direct steam stripping, thermosiphon type, recycle back the sour water from KO drum to feed, upstream degassing vessel, min 20’ as holdup time to allow separation of hydrocarbons for degassing drum, provide a buffer tank Downstream degassing drum, add top pumparround using an air cooler. The bottom temperature 121C and please desuperheat the steam to minimize reboiler surface and provide steam condensate pot not steam trap. Specification: if NH3 is present set 20 ppm wt in bottom product. Depends by simulator use the built-in thermo package & don’t panick if an electrolyte package is not available-the differences are in 2-5 %, under 10%. Size the column using vendor available software targeting 80% for FF. Mihail

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Rigorous depressurization to find the metal wall temperature creates big savings - below an example of using arctic steel (-70C) instead of expensive SS:

Documents:

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Aromatic Extraction & B/T Separation-Extractive distillation seems to be most robust in comparison with classical extraction technique. The most important players are Axens, UOP, GTC & Uhde, using proprietary solvents like sulfolane, morphylane, techtiv. There is always a debate between old sulfolane and new techtiv use for extractive distillation. The next numbers are estimated for 1000 kg/h of benzene as product from Aromatic Extraction & B/T Separation Plant using sulfolane & techtiv: power consumption 35% higher for techtiv; CW 7 (seven) times lower for techtiv; HPS /MPS: 2 wt. % / 50 wt. % more for techtiv; LPS: sulfolane 2 t/h & techtiv nil; BFW: sulfolane nil & techtiv 0.1 t/h; solvent plant inventory: sulfolane 40 % vol. lower; MEA injection kg/year sulfolane 2 kg versus 300 kg and antifoam agent kg/year: techtiv 20 kg vs 200 kg for sulfolane. Regarding CAPEX, even with DWC vs normal config- bz/toluene towers&consid. CS as MOC for this Plant, techtiv can’t beat sulfolane.

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Separator liquid level:

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And the last snapshop Max cooling water velocities:

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SGP rigorous simulation- BFD below:

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Detail rigorous procedure to optimize fractionation columns:

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Amine unit content:

6.​Amine Recovery​

6.1.​Introduction​

6.2.​Block Flow Diagram​

6.3.​Process Description​

6.4.​Simulation Tips & Tricks​

6.4.1.​Thermo package​

6.4.2.​Simulation layout​

6.4.3.​Pressure drop​

6.4.4.​Absorber and Regenerator​

6.4.5.​Amine Unit temperature profile​

6.5.​Design Recommendation​

6.5.1.​General design recommendation​

6.5.2.​Rich flash drum​

6.5.3.​Lean / rich amine heat exchanger​

6.5.4.​Amine stripper reboiler​

6.5.5.​Let down control valve on rich amine​

6.5.6.​Off gas from rich flash drum​

6.6.​Take Away

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Crude Distillation Unit index:

14.​Crude Distillation​

14.1.​Introduction​

14.2.​Block flow diagram​

14.3.​Process Description​

14.4.​Simulation Tips & Tricks​

14.4.1.​Thermo package​

14.4.2.​Characterization of crude oil​

14.4.3.​Translation of actual trays to theoretical trays​

14.5.​Schemes to Increase Crudes Processing Capacity​

14.6.​Crude Distillation: Packing Versus Trays​

14.7.​Preflash Column​

14.8.​Naphtha Stabilizer​

14.9.​Naphtha Splitter​

14.10.​CDU – Process Monitoring​

14.11.​CDU – Test Runs for Equipment Rating​

14.12.​CDU – Strategy for Column Rating/Simulation​

14.13.​Fouling Margins for Tubular Heat Exchanger Design​

14.14.​Desalting​

14.15.​Atmospheric Column Top Corrosion​

14.16.​Take Away

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SRU - to understand how important is to provide the right air flow rate:

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CDU overflash definition:

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CPA validation agaist experimental data, just an example from extensive graphs presented in eBook:

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Another snapshop from eBook - What it is happens in de-C1 overhead - see below fig and how to simulate this complex system:

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Just an inside flavor - GOR calculation block:

- Adjust GOR and water content as per production profile: use a simple calculation block to set oil and gas production and water (pay attention at units of measure & set the normal conditions as per project specification – suppose 1.0133 bara / 15°C), remove water from the indicated well composition for oil and gas streams to close heat & mass balance

- Combine the gas, oil and water streams to obtain the corrected composition bassed on production profile as per fig:

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The structure of the chapters shall be kept simple providing key information to build the simulation, finishing with design recommendation for unit and critical equipment plus Take away section to be discovered by the reader:

1.​Floating Production Storage and Offloading​

1.1.​Introduction​

1.2.​Block Flow Diagram​

1.3.​Process Description​

1.4.​Simulation Tips & Tricks​

1.4.1.​Thermo package​

1.4.2.​Simulation layout​

1.4.3.​Pressure drop​

1.4.4.​Compressor and pump efficiency​

1.4.5.​Heaters and coolers outlet temperature​

1.4.6.​Separators carry-over​

1.5.​Design Recommendation​

1.6.​Take Away​.

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Subject no. 47 - my intention is to share from my experience in Upstream, Midstream and Downstream in a book and I kindly desire your feedback regarding this! I am thinking to cover simulation & design tips from FPSO, GOSP, Amine, NGL with Frac Train, Molsieve & Glycol, CDU & VDU, Reformer Splitter & Stripper, FCC Main Column & Gas Plant, Hydrocracking Frac Section, Benzene/Toluene/Xylene frac .... The main idea is to be neutral, meaning that simulation could be made in any flowsheeet simulator, with specific thermo package. Some special chapters like MDMT and HIPS.

What do you think?

Thank you for your feedback!

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10/13 rule aplication on HX design pressure. Any idea from safety point of view ? What is the main benefit raising the design pressure? The main reason to aply 10/13 rule, which increase the design p of low side (liquid full) when tube rupture shall occurs over time, due to 10/13 the hydrocarbon leak to environment is avoided. If gas is present on lower p side I suggest to make an economic analysis to SEE if it is cheap to apply 10/13 rule or to add a PSV. Anyway the gas is compressible fluid and the liquid Shock wave that Could distroy HX is not applicable for this case because the gas would atenuate the wave. If 10/13 rule will be implemented then the PRV is not necessary to be computed for tube rupture. Good Engineering practice and experience will recommend to extend the 10/13 rule to HX isolation valves, including them, because after tube rupture occurs the distructive liquid pressure wave will disipate in the large available network of low pressure side.